Power Generation » Gas Turbine

Urquhart Repowering Project, Beach Island, South Carolina

japat30 — Tue, 24 Jun 2008 07:16:47 +0000

Owned and operated by South Carolina Electric & Gas Co.

For many utilities, repowering a 50-year-old coal-fired plant has become an attractive alternative to making expensive environmental upgrades to such a plant reaching the end of its useful life. Repowering is especially attractive if the plant’s existing water and air permits can be “recycled.” South Carolina Electric & Gas Co. was able to do just that at its Urquhart Station a few years ago. By repowering the plant’s older two units and cross-connecting them with Unit 3, the utility boosted Urquhart’s overall efficiency and operating flexibility. Creative engineers found a way to squeeze every dollar of savings from this plant.

By Skip Smith, Project Manager

South Carolina Electric & Gas Co. (SCE&G), a subsidiary of Scana Corp. (Columbia, S.C.), built the Urquhart Station’s original three coal-fired units—two 75-MW GE steam turbines and another rated at 100 MW—in the early 1950s. The plant (Figure 1) is located in Beach Island, S.C., on the Savannah River near Aiken City.

1. Urquhart Station.

South Carolina Electric & Gas Co.’s 1950s-vintage Urquhart Station was repowered with two GE 7FA gas turbines using the two existing 75-MW steam turbines. Plant output increased from 250 MW to 550 MW.

Courtesy: South Carolina Electric & Gas Co.

By 1999, environmental pressures, rapidly escalating maintenance costs, and service territory load growth were straining SCE&G’s generating resources. The solution: Invest $228 million and repower the older two units to create a modern, combined-cycle facility based on GE 7FA gas turbines (GTs). The other GTs at the site are three 15-MW peakers installed in the 1960s and a 42-MW GE LM6000 simple-cycle peaker installed in 1999.

The repowered plant is an intermediate service plant, operated during times of high load demand. During the summer and winter months, the plant is generally operated 10 to 16 hours per day. For the first full year of operation, GT-1 produced 541,000 MWh and GT-2 produced 520,000 MWh. The plants operated 4,668 and 4,544 hours, respectively.

Beyond the addition of a badly needed 300 MW, the repowering project promised other benefits:

It would allow SCE&G to retain Urquhart’s well-trained workforce.
It would allow retention of the plant’s water discharge permit.
By effecting a significant drop in NOx, SO2, and particulate emissions from Urquhart, the project would delay the need for SCE&G to install a selective catalytic reduction system on one of its other coal-fired plants (Figure 2).

2. Repowering benefits.

The repowering project enabled Urquhart Station to retain its existing water discharge permit. But perhaps more important, the reduction in emissions that resulted from removing the old coal-fired Units 1 and 2 from service enabled SCE&G to delay the installation of a selective catalytic reduction system on one of its other coal-fired plants.

Courtesy: South Carolina Electric & Gas Co.

Upon commissioning of the new combined-cycle plant, Units 1 and 2 were taken out of service. Unit 3—rated at 100 MW—was kept on-line. As a result, the new plant has an output of 550 MW.

Duke/Fluor Daniel was selected as the EPC contractor for the repowering project in April 2000. Site preparation began that spring, and construction began in September 2000 immediately following receipt of an air permit for the plant. First fire was in March 2002, and the plant was declared commercial on June 1, 2002—ahead of schedule.

Greater operating flexibility

The new Urquhart Station has a 1 x 1 combined-cycle configuration. Each GE 7FA exhausts into a Nooter/Eriksen (St. Louis, Mo.) heat-recovery steam generator (HRSG). Steam conditions are 1,440 psig/1,000F superheat and 1,000F/366 psig reheat. The HRSGs are single-pressure units configured as follows: reheater-HP superheat 2-HP superheat 1-HP evaporator-HP economizer-Unit 3 feedwater heating.

One of the plant’s unique features is the cross-connection of the steam turbines for improved operational flexibility. In fact, both 75-MW steam turbines can be operated with a single gas turbine under steady-state conditions (Figure 3). These cross ties include hot and cold reheat connections for the reheat steam turbines. The reheat cross connection was predicated on an innovative design by Duke/Fluor Daniel and GE. The flexibility of this “semi-plant” mode of operation provides for more timely and economic dispatch of the facility.

3. Flexibility.

Plant main steam is cross-connected to the two 75-MW steam turbines for improved operating flexibility. Both steam turbines can be operated with a single combustion turbine.

Courtesy: South Carolina Electric & Gas Co.

The design also allows the cold start of both steam turbines by one gas turbine. A cascading steam bypass from the HRSG to the condenser using the cold and hot reheat lines allows each GT to continue operating when both steam turbines are out of service. As part of the project, the steam turbines and generators of Units 1 and 2 were refurbished and upgraded to make them compatible with combined-cycle operation.

Another unique feature of the facility design is the use of steam generated by the HRSGs of repowered Units 1 and 2 to heat HP feedwater for the existing Unit 3 steam turbine (Figure 4). This not only increases the operational efficiency of Unit 3 but also the operational flexibility of the overall plant.

4. Steam use.

Steam generated by the HRSGs of the repowered Units 1 and 2 is used to heat the HP feedwater of the existing Unit 3 steam turbine. The net effect is an improvement in the overall plant’s efficiency and operating flexibility.

Courtesy: South Carolina Electric & Gas Co.

Other areas of the plantthat were upgraded included the fuel oil backup system for the gas turbines and the chiller for their inlet air. The latter step, which boosted output of the GTs by up to 20 MW, entailed the installation of inlet coolers from Caldwell Energy and Environmental Inc. (Louisville, Ky.). The plant’s 1.2-million-gallon oil tank can supply both gas turbines for five 16-hour operating days.

Control upgrades included a new distributed control system (a Westinghouse Ovation), the addition of a GE Mark VI system for controlling the Unit 3 steam turbine, and new electro-hydraulic controls for the steam turbine control valves. Balance-of-plant upgrades weren’t overlooked either: Higher-capacity demineralized water system and condensate pumps were added to complement the existing water treatment system (Figure 5).

5. Control system.

A new plant distributed control system was added along with a new GE Mark VI control system for the Unit 3 steam turbine.

Courtesy: South Carolina Electric & Gas Co.

Gas turbine combustors drive emissions toward nil

japat30 — Tue, 24 Jun 2008 07:06:14 +0000

Best available control technology continues to be ratcheted down to achieve ever-lower NOx emissions. Some dry low-NOx combustors can achieve 9 ppm without post-combustion control, while newer catalytic combustors are operating below 5 ppm NOx.

In the late 1980s, gas turbine original equipment manufacturers (OEMs) began to integrate dry low-NOx (DLN)—also referred to as dry low-emission (DLE)—combustion technology into their product lines to eliminate the need for steam or water injection, which had been the traditional method of NOx control. Many DLN technologies were evaluated, and lean premixed combustion emerged as the most promising approach for near-term application.

Throughout the next decade, lean premixed combustors installed in new models and retrofits to existing units dramatically slashed NOx emissions compared with conventional diffusion flame technology (Figure 1). But, like so many things in nature, the benefits of NOx reduction came at a price. Because the optimum flame temperature of a lean premixed combustor is close to the lean flammability limit, combustor performance is characterized by a CO/NOx tradeoff. At the combustor design point, both CO and NOx are below target levels; however, deviations from the design flame temperature cause emissions to increase. This tradeoff becomes particularly important during part-load turbine operation, when the combustor is required to run even leaner (Figure 2, p. 24).

1. NOx limits

Best available control technology (BACT) NOx limits have plummeted in the past 20 years. Will 5 ppm NOx soon become the national standard?

Source: U.S. Department of Energy

The power output of a gas turbine is directly related to the firing temperature, which is directly related to flame temperature and the rate of thermal NOx formation. The formation of NOx increases dramatically when the temperature exceeds 2,900F on natural gas. Because traditional diffusion flame combustor temperatures can exceed 4,000F for brief periods, it is virtually impossible to achieve ultra-low NOx levels when a turbine is fired with a diffusion flame combustor.

Key: Low flame temps

Low emissions of NOx, as well as CO, can be achieved with thorough fuel-air mixing and control of the adiabatic flame temperature below about 3,000F. If, on the other hand, the peak combustion temperature can be limited to about 2,800F, NOx levels can be less than a few parts per million (ppm). Unfortunately, at fuel-air ratios low enough to achieve such low NOx concentrations, flames are highly unstable and are susceptible to flame-out or fluctuations, which can cause severe combustor vibrations and fatigue failure of combustion components.

In contrast to lean premixed combustion, an alternative technology known as “catalytic combustion” does not involve issues of flame stability. The fuel-air ratio entering the catalyst simply needs to be high enough to generate the desired turbine-inlet temperature at full conversion of the fuel.

One of the great difficulties with lean premixed systems is maintaining flame stability in the narrow flame temperature range between high NOx production and lean flame extinction. Aerodynamically stabilized injectors have very narrow ranges of operation, necessitating multiple burner staging (up to four stages in some systems) or piloting. Many turbine manufacturers have refined their DLN systems to sub-25 ppm NOx levels, and some Frame units have achieved single-digit, or sub-10 ppm, NOx levels.

Whereas the U.S. spends millions for increased capital and maintenance costs for the latest DLN technology and postcombustion cleanup equipment to reach ever-lower NOx limits at virtually all powerplants, the European Union has taken a different approach: The EU sets NOx limits based on plant efficiency. For example, the NOx requirement for simple-cycle units with an efficiency greater than 35% is approximately 24 ppm on natural gas and 58 ppm on liquid fuels. Gaseous fuels other than natural gas have a limit of 58 ppm.

NOx limits are less stringent for gas turbines used in combined heat and power systems demonstrating an overall efficiency greater than 75% and for combined-cycle plants demonstrating an annual average electrical efficiency greater than 55%.

Solar does DLE

The first two prototype production DLE systems manufactured by Solar Turbines Inc (San Diego, Calif.) were installed in 1992 for field evaluation. These were a Centaur 50S gas turbine, rated 4.1 MW, at El Paso Natural Gas Co’s Window Rock Station near Window Rock, Ariz., and a Mars 100S gas turbine, rated 10.5 MW, at the Pacific Gas Transmission station near Rosalia, Wash. Initially, high combustion pressure oscillations limited operation to 42 ppm NOx. The oscillations were controlled in the short term by raising pilot fuel flow, but this increased NOx and CO. The pilot fuel injector circuit is used mainly for light-off and low-load operation. During light-off and low-load operation, approximately 30% to 50% of the fuel passes through the pilot injector, providing a rich fuel-air mixture and improved combustion stability. Above 50% load, the pilot fuel is reduced to less than 5% of the total fuel flow to optimize emissions performance (Figure 3, p. 26).

2. Emissions compromises

Combustor design is a series of compromises between robust operation at all loads versus lower NOx and CO. Lean combustion also increases combustion noise–caused fatigue failure of combustion components in early DLN systems.

Source: Platts

3. Dry low-emission (DLE) fuel injectors

DLE fuel injectors are significantly larger than conventional ones due to the higher airflow through the injector air swirler and the required volume of the premixing chamber. The injector module includes a premixing main fuel injector and a pilot fuel injector.

Courtesy: Solar Turbines Inc

Design of Solar’s fuel injector premixing section was optimized by the mid-1990s. This reduced combustor pressure oscillations and, when combined with injector design improvements, enabled emissions warranties of 25 ppm NOx on natural gas and 96 ppm NOx on liquid fuels. This guarantee was extended to all of Solar’s models.

In 2001, an augmented backside-cooled combustor liner was incorporated into the OEM’s Centaur 50S and Taurus 60S models, allowing a further emissions reduction to 15 ppm NOx and 25 ppm CO from 50 to 100% load, following more than 22,000 hrs of field testing.

The most significant difference in Solar Turbines’ new lean premixed combustor liner is the increased combustor volume required for low CO and unburned hydrocarbon (UHC) emissions at the lower overall flame temperature. Because combustor length was constrained by field retrofit opportunities, the only option was to increase the diameter of the combustor liner. A second difference is the absence of large air injection ports in the combustor primary zone. All air used in the combustion process is introduced through the air swirler of the fuel injectors (Figure 4, p. 26).

4. Larger-diameter combustor liners

The increased volume of the DLE combustor required the diameter to increase while holding the length constant so existing engines could be retrofitted. High- time DLE combustor liners have more than 39,000 operating hours.

Courtesy: Solar Turbines Inc

The new DLE combustor incorporates the capability to regulate the combustor airflow and pilot fuel flow over the entire engine-operating map. The requirement to control these two parameters has added a degree of complexity to the control system that is not required in a conventional gas turbine. During start-up and low-load operation, the pilot flow rate has been optimized to achieve maximum flame stability to handle load transients. Below 50% load the combustor airflow is managed in the same way as in a conventional engine. Above 50% rated load, Solar’s DLE engine enters the “low emissions mode,” modulating either the bleed valves or inlet guide vanes to keep the combustion primary zone temperature within a specified range. Solar’s DLE gas turbine controls use the power turbine inlet temperature as an indirect measurement of the primary zone temperature to control the bleed valve or inlet guide vane position as a function of turbine load (Figure 5).

5. SoLoNOx system

A Centaur 50 gas turbine with a dual-fuel SoLoNOx system supplies power and heat to a district energy system in Germany.

Courtesy: Solar Turbines Inc

Local ambient conditions also affect emissions. NOx is observed to increase with increasing ambient temperature, decreasing relative humidity, and increasing barometric pressure, whereas CO emissions trend in the opposite way. However, field experience has shown that relative humidity and barometric pressure have only a small effect on the combustor primary zone temperature and, therefore, a small influence on emissions from DLE gas turbines. In practice, emissions from DLE packages vary less than 5 ppm from 0F to 120F. Many DLE packages are configured to increase pilot fuel flow at temperatures below 68F to augment flame stability. Below 0F, NOx and CO emissions increase.

Further reductions

Future emissions reductions mean developing new technologies to take up where DLE leaves off. One area being explored by Solar Turbines is a surface-stabilized fuel injector for use with lean, premixed combustors. Developed by Alzeta Corp (Santa Clara, Calif.), surface-stabilized fuel injectors provide extended turndown and ultra-low NOx emission performance.

The new injectors form interacting radiant and blue-flame zones immediately above a selectively perforated porous metal surface. This allows stable operation at low reaction temperatures. A proof-of-concept injector in a full-pressure test rig at the U.S. DOE’s National Energy Technology Laboratory in Morgantown, W.Va., achieved sub-3 ppm NOx emissions with concurrent single-digit CO emissions. Operating conditions ranged between inlet pressures of 26.5 psia and 180 psia, inlet temperatures between 186F and 850F, and calculated adiabatic flame temperatures between 2,670F and 2,900F. Testing with prototype fuel injectors in test rigs at Solar Turbines yielded similar results. In May 2001, the OEM’s 1-MW Saturn gas turbine was operated to 95% load with a surface-stabilized injector. Currently, Alzeta and Solar Turbines are completing a multi-burner annular combustor test, which will then proceed to an engine test later this year. In addition, the companies have initiated a project to apply Alzeta’s nanoSTAR technology to the Titan 130 gas turbine.

Mitsubishi hits 15

Mitsubishi Power Systems Inc’s (Lake Mary, Fla.) first DLN combustor was introduced in 1984 on a 50-Hz M701D gas turbine. By 1992, 25-ppm NOx levels were being commercially achieved in the OEM’s F-class turbine operating at full load, with a turbine inlet temperature of 2,460F.

Mitsubishi’s F-class fleet experience with DLN combustors now exceeds 1.5 million hours of meeting the 25 ppm NOx limit. The OEM reports that recent tests have achieved 15 ppm NOx.

The pilot nozzle and air bypass valve in this combustor make it possible to sustain a stable flame and accurately control the fuel-air ratio. The main nozzles are composed of air swirlers together with a fuel nozzle. The swirlers introduce highly turbulent air, causing complete mixing of gas and air, while the pilot nozzle allows stable combustion of the premixed gas by diffusion firing. A cone attached at the tip makes flame holding stable by recirculating combustion gases. The air bypass valve, infusing air directly into the transition piece, is installed at the transition piece, enabling an almost constant fuel-air ratio at various operating conditions, such as ignition, acceleration, and partial-load operation (Figure 6).

6. Contrasting cooling schemes

The cooling scheme in Mitsubishi’s F-class turbine uses proprietary “Platfin” cooling of the combustor basket, and “Mtfin” is used at transition piece. Around 10% of available air is used for cooling, and the rest is used for combustion. The G-class combustor uses steam for cooling (bottom).

Courtesy: Mitsubishi Power Systems Inc

In 1996, a steam-cooled DLN combustor was developed for Mitsubishi’s G-class gas turbines. The M501G and M701G models feature a turbine inlet temperature of 2,730F and are designed to achieve a combined-cycle plant efficiency of greater than 58%. Prototype testing has shown the G series to be capable of 25 ppm NOx.

To increase the turbine inlet temperature to 2,730F, almost all of the compressed air is needed for combustion, and steam is introduced to perform the cooling. (In conventional gas turbines, much of the compressed air is diverted to cool hot-gas-path components.) Overall, Mitsubishi’s G-class combustor has nearly the same configuration as its F class, except at the combustor basket, where the transition piece integrates the basket part and the liner. The cooling steam, supplied from a required bottoming steam cycle, cools that structure over the entire surface area of the combustor.

The M701G1 combustion chamber and first- and second-stage blades and vanes are similar to those used in the prototype 501G design, but the size has been increased to give a higher output. The 701G1 is a single-shaft machine with the generator at the compressor end of the turbine to allow the turbine exhaust to be directed into the heat-recovery steam generator. The turbine combustion chamber uses steam cooling to maintain temperature in the range 2,730F to 2,910F to keep NOx emissions at 25 ppm or less. Mitsubishi’s G-class fleet experience exceeds 75,000 hours on seven units.

Aero engines

GE Power Systems’ (Atlanta, Ga.) DLE combustors have been developed for GE’s aeroderivative gas turbines—the gas-fueled 44-MW LM6000, the 23-MW LM2500, and the double annular 15-MW LM1600. Twenty-five ppm has been successfully demonstrated for the entire family of LM DLE products.

Factory testing of components and engine assembly on the first 41-MW DLE LM6000 gas turbine was completed in 1994 and demonstrated less than 15 ppm NOx, 10 ppm CO, and 2 ppm UHC at a firing temperature of 2,350F. In 1995, the 43-MW Ghent power station in Belgium became the first commercial operator to use the LM6000 fitted with the DLE combustor system, demonstrating 16 ppm NOx, 6 ppm CO, and 1 ppm UHC. The high-time LM6000 engine has accumulated more than 34,000 hours. As of the end of 2002, GE had more than 200 DLE LM engines in operation with almost 3.5 million operating hours.

The LM6000 DLE combustor employs a triple-dome design with staging of fuel and air flow to achieve lean premixed operation from light-off to full power—using the mid-dome at light-off, with the inner and outer domes brought on progressively as the engine is loaded. The middle and outer domes each consist of 30 premixers; the inner dome has 15. The domes of the combustor are protected from the hot combustion gases by segmented heat shields.

The middle and the inner dome premixers are identical, but the outer premixers are somewhat larger to manage the dome reference velocities in the three combustor domes within a narrow band. Spent cooling air from the heat shield is directed away from the flame-stabilization zones, permitting the combustor to operate at leaner fuel-air ratios. Turbine-nozzle cooling air is utilized to cool the liners convectively on the backside. Combustion acoustics are controlled by the use of passive devices on the exterior of the engine, fuel staging within premixers, and by the use of a control system that senses and alters the combustor operation to limit combustion-generated noise. A small amount of fuel (about 10% of the middle dome flow) is injected into the combustor from holes in the walls of the mixing duct. Another feature, Enhancing Lean Blow Out holes, increase the local fuel-air ratio in the mixing region between recirculating burned gases and fresh, incoming mixture and also provide axial staging of the fuel. The increased fuel-air ratio in the mixing region, along with axial staging, helps to decouple any fuel injection–related acoustic coupling mechanisms (Figure 7).

7. Individual fuel controls

The LM6000PD has individual fuel controls for each of the combustion system’s three domes.

Courtesy: GE Power Systems

The NOx emissions stay low as the combustor operates lean premixed over the entire operating envelope. CO emissions are less than 25 ppm levels at 50% power on up. UHC emissions are typically less than 10 ppm everywhere except during start-up. Higher emissions are encountered transiently during staging when additional domes are either being lit or extinguished.

The LM1600, LM2500, and the LM6000 are two-shaft engines. Unlike in single-shaft engines, the compressor discharge temperatures and pressures increase as the load increases. Higher combustor inlet air temperatures result in a decrease in flame quenching and thus the lean blowout limit moves to leaner fuel-air ratios and lower flame temperatures. The combustor can operate with lower flame temperatures as the load is increased. NOx emissions decrease slightly as the load on the engine is increased in the region where the flame temperatures are held constant with airflow control. Once the load increases past the point of airflow control, additional power is produced by simply increasing the flame temperature.

CO emissions are strongly dependent on the quenching of the CO oxidation process in the neighborhood of the combustor liners. Leakage air from the heat shields also contributes to the early quenching of the CO oxidation reactions. In order to reduce quenching of the CO oxidation reactions in the forward regions of the primary combustion zone, cooling air and leakage airflows in this region have been kept at minimum by the use of advanced cooling technology and materials.

Single-digit NOx

The only utility-scale gas turbine currently marketed with single-digit NOx guarantees is GE Power Systems’ Frame 7FA outfitted with DLN-2.6. The first of these units was placed in service in March 1996 by Public Service Co of Colorado. The newer model reduced NOx levels from the OEM’s previous 25-ppm guarantee on the DLN-2 combustor down to 9 ppm. This required 6% more air to pass through the premixers in the combustor due to reductions in cap- and liner-cooling airflows and increased cooling effectiveness.

However, without changes in the operation of the DLN-2 system, certain penalties would have been incurred for achieving 9 ppm baseload performance. The turndown of a DLN-2 combustor tuned to 9/9 operation (9 ppm NOx/9 ppm CO) was estimated to be about 70% load, compared with 40% load for the 25/15 system. A new combustor configuration was developed based on the DLN-2 burner because of its excellent flame-stabilization characteristics and operating experience. The key feature of the newer configuration is the addition of a sixth burner located in the center of the five existing DLN-2 burners. The presence of the center nozzle enables the DLN-2.6 to extend its 9/9 turndown well beyond the five-nozzle DLN-2.

By fueling the center nozzle separately from the outer nozzles, the fuel-air ratio can be modulated relative to the outer nozzles leading to approximately 200F of turndown from baseload with 9 ppm NOx. Burners were turned and a fourth premixed manifold for injecting quaternary fuel was added to reduce combustion dynamics. The first three premixed manifolds, designated PM1, PM2, and PM3, are configured such that any number of burners can be operated at any time. The PM1 manifold fuels the center nozzle, the PM2 manifold fuels the two outer nozzles located at the cross-fire tubes, and the PM3 manifold fuels the remaining three outer nozzles. The five outer nozzles are identical to those used for the DLN-2, while the center nozzle is similar but with simplified geometry to fit within the available space. Emissions performance of the DLN-2.6 is 9 ppm NOx and CO over a 50% load range.

GE recently announced a series of power and efficiency uprates, as well as NOx reductions, to its Frame units. This includes the PG6111FA (the uprated version of the Frame 6FA), which generates 75.9 MW with 15 ppm NOx at a firing temperature of 2,420F. The Frame 6FA machines are manufactured in GE’s facility in Belfort, France, and are scheduled to start shipping in the second quarter of 2003.

GE also introduced the Frame 9FB, a 50-Hz version of the 7FB, which was introduced in 1999. The first 7FB was installed at a Reliant Energy project in Hunterstown, Pa., where it is being tested and is scheduled to enter commercial service in 2003. The Frame 9FB benefits from what GE calls an “advanced technology flowback” from the company’s planned steam-cooled H-class gas turbine. The 9FB will be equipped with GE’s advanced DLN-2+ combustion system, and NOx emissions will be less than 25 ppm. The Frame 9FB will be available for shipment in early 2004.

Catalytica cleans up

A technology called catalytic combustion promises to be an alternative to DLN technologies, with even lower NOx levels—below 5 ppm. Catalytica Energy Systems Inc (Mountain View, Calif.) took an early lead in this field in 2000, when it installed its Xonon system on a 1.4-MW Kawasaki gas turbine at Silicon Valley Power’s (Santa Clara, Calif.) Gianera station. Catalytica recognized that it’s tough to break into the gas-turbine business with a potentially revolutionary new product, especially when the product lies directly in the gas path. “Show me an operating turbine and then we’ll talk,” was the message.

So the company went it alone by purchasing a used M1A Kawasaki engine, refurbishing it, and retrofitting its new combustion system designed from scratch. Catalytica did this before Kawasaki Motors Corp USA (Grand Rapids, Mich.) decided to come on board, license the technology, and develop what is now the commercial product. After 14,000 grid-connected hours and a yearlong 8,128-hr testing program, the Silicon Valley Power plant performed better than design. According to Catalytica, the results were:

NOx emissions of 1.3 ppm (goal was less than 3 ppm)
CO emissions of 0.9 ppm (goal was less than 5 ppm)
UHC emissions of 1.3 ppm (goal was less than 5 ppm)
Reliability of 99.2% (goal was 98%)
Availability of 91.2% (goal was 96%)

Kawasaki Heavy Industries Limited (Hyogo, Japan) produces the 1.4-MW M1A-13A gas turbine (referred to as the M1A-13X when Xonon is installed). The model has an unimpressive thermal efficiency of just 25.5%—equating to a 13,400 Btu/kWh heat rate. But it is convenient for a Xonon retrofit because it has a readily accessible, single, external can-type combustor. The M1A-13A has a pressure ratio of approximately 9.3 to 1, which is comparable to that found in many other industrial gas turbines in the 1- to 6-MW range. Also, the model’s low mass flowrate (18 lb/sec) allows the catalytic combustor to be maintained as a small system typical of large rig test units, thus reducing the cost of the total system. Finally, its low firing temperature of 1,839F makes the engine ideal for catalytic combustion, because the modest temperatures in the gas-phase burnout zone allow the use of existing liner-cooling technologies.

In the Xonon combustion system, compressor discharge air enters an annular plenum prior to entering the preburner. The preburner is a small DLN-type combustor that preheats the combustor air up to the catalyst operating temperature. Fuel is then injected into the warm air and thoroughly mixed before entering the catalyst module. In the catalyst module, some of the fuel-air mixture is combusted through a flameless catalytic process. The combustion process continues in the burnout zone until all of the remaining uncombusted fuel is reacted (Figure 8).

8. Catalytic combustor

Catalytic combustors burn lean fuel-air mixtures to achieve sub-5 ppm NOx. The maximum combustor exit temperature is 2,460F or lower—well below the NOx-formation temperature.

Courtesy: Catalytica Energy Systems Inc

According to Catalytica, its technology is superior if your target is 5 ppm NOx or less, meaning the life-cycle cost of a Xonon-equipped gas turbine is less than that for the same gas turbine equipped with a selective catalytic reduction system. The manufacturer points out that spent Xonon catalysts, which are expected to be depleted annually, are nontoxic and can be recycled to recover precious metals.

The OEM successfully completed an Equipment and Process Precertification Program administered by the California Air Resources Board (CARB), which verified the air quality–related performance claims of its Xonon Cool Combustion system last August. The Equipment and Process Precertification Program is a voluntary statewide program administered by CARB through which manufacturers of products that have a beneficial impact on air quality can have their product’s performance claims independently verified. The objective of the program is to simplify the permitting process by providing advanced independent evaluation of a technology, which can then be used as the basis for BACT (best available control technology) determination.

Last year, Xonon shipped catalysts for what was scheduled to be the first three commercial Xonon-equipped Kawasaki gas turbines for a government healthcare facility in Jamaica Plain, Mass. However, the plant was being developed by an Enron subsidiary, and the project was shelved after the turbines were shipped. After the three turbines had sat idle for over a year, Kawasaki repurchased them at an auction of Enron assets.

The first commercial application of Catalytica’s Xonon technology now is the Sonoma Developmental Center in Eldridge, Calif., where an existing Kawasaki M1A-13D gas turbine was retrofitted with a Kawasaki-designed Xonon-based combustor (Figure 9). The 12-yr-old unit provides supplemental heat and power for a staff of 2,200 and 850 residents across 120 buildings.

9. First commercial catalytic combustor installation

The Sonoma Developmental Center is the first commercial catalytic combustor installation. A 12-yr-old Kawasaki gas turbine was retrofit with a Catalytica-licensed catalyst. Post-startup testing confirms that the 1.3-MW plant is operating at less than 3 ppmv NOx, less than 10 ppm CO, and less than 2 ppm VOC.

Courtesy: Catalytica Energy Systems Inc

The six-week retrofit involved removing the current M1A-13D engine operating with a DLE combustor configuration, and replacing it with an advanced M1A-13X engine incorporating Xonon Cool Combustion. The reconfigured unit returned to service in November 2002. Post-startup testing confirms the 1.3-MW plant is operating at less than 3 ppm NOx—an overall 90% reduction. Additionally, the Xonon Cool Combustion system makes it possible for Kawasaki to guarantee CO levels of less than 10 ppm and VOC levels of less than 2 ppm.

Catalytica announced in December the purchase of a Kawasaki 1.4-MW GPB15X equipped with Xonon technology. The unit is part of a heating and cooling plant for the Reader’s Digest 650,000-square-foot global headquarters in Pleasantville, N.Y., servicing approximately 1,000 employees. The plant is expected to be in service by this July.

Catalytica reports that it also has demonstrated sub-5 ppm NOx levels on gas turbines manufactured by Rolls-Royce Allison (Indianapolis, Ind.). GE Power Systems plans to begin shipment of a Xonon-equipped 11-MW GE10 gas turbine in 2004. String testing is scheduled in Florence, Italy, this year with orders beginning this fall. Emissions targets for the GE10 are 3 ppm NOx, 100 ppm CO, and 10 ppm VOC.

By Dr. Robert Peltier PE, Sr. Editor

Designing and modifying HRSGs for cycling operation

japat30 — Tue, 24 Jun 2008 07:04:42 +0000

Designing and operating HRSGs for cycling duty requires close cooperation between the manufacturer and the user. Once HRSGs are in service, a monitoring system should provide a thorough picture of the mechanisms affecting the life and integrity of the boiler.

Today’s heat-recovery steam generators (HRSGs), a vital component in the popular combined-cycle plant, are exposed to more severe duty than merely running at baseload. Deregulation has spurred the development of merchant plants, which are required to start up, load follow, and shut down with minimal notice in response to market conditions. Unless properly designed and operated to withstand this cycling duty, the integrity of the HRSG will be compromised.

Industry professionals need to understand the various damage mechanisms that can result, as well as how to control them. For new projects, damage control begins with the specification of certain design features. Operation and maintenance practices also play an essential role in managing HRSG life, both for new and existing plants. Existing plants also should explore modifications and monitoring programs that can boost the reliability and extend the service life of HRSGs in cycling duty.

Many components

Existing HRSGs that are already in service pose another problem. Most of these were designed for baseload operation but now are being cycled. Users should explore the HRSG modifications that are discussed below to determine the applicability to their specific plants. At a minimum, users of existing HRSGs should implement a monitoring program, outlined here, to gauge the effects of cycling.

A typical combined-cycle HRSG produces “main steam,” at three pressure levels, plus “reheat steam.” Supplemental firing through a duct burner often is installed, as well, to increase steam-production capacity. Most combined-cycle plants also have a feedwater heater to increase the heat recovery and reduce the deaerating load of the integral deaerator.

The heat-transfer sections of the HRSG are located in series along the exhaust-gas path to optimize heat recovery. It is not uncommon to have 15 to 20 different heat-transfer sections—superheaters, reheaters, evaporators, and economizers—at various locations along the gas path. Emissions-control regulations often require the addition of a selective catalytic reduction system (SCR) for NOx control and, in some cases, a separate catalytic converter for CO control. Some HRSGs also are equipped with an exhaust-gas bypass damper to enable simple-cycle gas-turbine operation, though these dampers have not found wide usage in the U.S.

Many mechanisms

All of these components are exposed to different temperatures and pressures at different times while the HRSG is started, operated, and shut down. How well the components react to the transients and steady-state conditions determines the integrity of the entire HRSG. The basic mechanisms affecting the life of an HRSG are:

Low-cycle fatigue (LCF). Damage occurs at a low number of stress cycles when the strain is high. LCF is the most dominant damage mechanism in today’s HRSGs.
Creep. Damage is caused by the material being at high temperature and stress for a considerable period of time.
Thermal shock. The impingement of cold water or steam on hot surfaces can damage the base material.
Oxidation. Oxidation and exfoliation can occur due to exposure to high temperatures.
Differential expansion. If adjacent tubes or pipes are at different temperatures, the resulting uneven expansion or contraction can stress both components. Piping supports also play a part in this.
Corrosion fatigue. A crack is initiated because of corrosion, and progressive damage occurs because of fatigue and corrosion. This typically occurs at a temperature range of 300F to 500F.
Corrosion in tubes. Improper water chemistry is the cause.
Flow-accelerated corrosion (FAC). The combination of high flow and poor chemistry control can cause FAC in specific HRSG locations.
Corrosion-product migration. The migration of corrosion products to other HRSG components may cause further corrosion or other damage.
Deposits. Temperature or water-chemistry fluctuations may result in deposits on heat-transfer surfaces.
Erosion. Transient high velocities may initiate or perpetuate erosion.

All components in an HRSG can be affected by these damage mechanisms (see Table). However, some components are more vulnerable because of their location, construction, or exposure. These critical components need to be designed and monitored more closely for potential failures. The critical components typically are:

Superheater and reheater outlets.
Tube-to-header joints in hot sections.
Drum-to-downcomer nozzles in the high-pressure drum.
Bent portions of heat-transfer tubes.
Attemperators.
Bypass valves.

To a plant operator, “cycling” refers to the quick start-up, load following, and shutdown of generating units. But to a materials engineer, cycling is the reversal of stresses in a component. Stress cycling can happen by the imposition and relaxation of loads or because of a reversal of temperatures. When a component is exposed to rapidly changing temperatures, all parts of the component may not heat up or cool down uniformly. The subsequent differential expansion creates high stresses and stress reversals.

The main causes of stress cycling are a change of plant load and emergencies. Plant load changes include short-notice start-ups, gas-turbine load changes, part-load operations, and varying duct-burner firing.

The way a boiler is shut down and laid up also can cause cycling. In an emergency—such as a steam-turbine trip—the boiler has to shut down very rapidly, causing undue, or reversing, stresses. Sometimes a boiler is force-cooled to make repairs during a short outage window. This force cooling can create temperature differentials. And the failure or abnormal operation of other plant equipment—such as pumps and valves—also can impose stress-cycling conditions on the HRSG.

Cycling relates to mechanisms

Most of the time, cycling either creates or exacerbates the effect of damage mechanisms on HRSG components. Creep damage, by definition, is caused by a prolonged exposure to high temperature and stress. Though creep is not caused by cycling, it is exacerbated by it. Fatigue and fatigue damage are the most prevalent mechanisms affecting the boiler life, and they are a direct consequence of cycling.

Water-chemistry upsets that result in corrosion may be due to cycling or to a failure of water-chemistry controls. For example, for a rapidly starting HRSG, the superheater is exposed to high temperature on the outside of the tubes and headers, while the inside surfaces of tubes and headers may still be cool. This creates high thermal stress. Some specific examples of how cycling creates or exacerbates the damage mechanisms in critical components are discussed below.

Superheaters and reheaters:

Fatigue. The impingement of hot gasses on cold surfaces at start-up or of cold gasses on hot surfaces at shutdown creates thermal gradients. Similarly, the condensed steam in the tubes after shutdown impinge on hot surfaces if the condensate remains in the tubes. The high-pressure components are more vulnerable to fatigue effects due to their increased wall thicknesses.
Thermal shock. Condensate in a superheater section or colder reheat steam in the hotter and dry reheater section would result in thermal shock to the inner surfaces of the tubes and headers.
Creep. Only high-temperature components are prone to creep damage. High-temperature transients and continuous high-temperature operation may increase the creep rate. However, if the creep is coupled with fatigue due to cycling, the damage will be much higher than what can occur if the same fatigue or creep is working alone.
Oxidation. Exposure of the metal to higher temperature than what it was designed for, particularly during start-ups, can result in oxidation. Oxidation and exfoliation can happen both inside and outside the tubes and piping, caused by exhaust gas on one side or steam/water on the other. Dry reheater designs are particularly vulnerable.
Differential expansion. Uneven heating of tubes—caused by uneven distribution of (1) exhaust-gas or steam/water flows or (2) exhaust-gas temperatures—can cause adjacent tubes to expand or contract differently. Both compressive and tensile loads are imposed.
Deposits. Uneven or excessively fast ramp rates may result in the accumulation of condensate in the superheaters and, consequently, the formation of deposits.

Evaporators:

Low-cycle fatigue. This often occurs in natural-circulation evaporators during start-up, because circulation has not been fully established.
Differential expansion. Just as with superheaters and reheaters, the uneven heating of evaporator tubes—caused by uneven distribution of (1) exhaust-gas or steam/water flows or (2) exhaust-gas temperatures—can cause adjacent tubes to expand or contract differently. Both compressive and tensile loads are imposed.
Deposits. Uneven heating or heat-flux anomalies may result in local dry-outs and deposition of salts in evaporator tubes. These deposits further distort the flow and heat-flux distribution, so the problem can snowball.
Flow-accelerated corrosion. Two-phase flows in evaporator sections result in FAC, particularly in the low-pressure sections.
Corrosion-product migration. Corrosion products formed at one location may migrate to another, and, under the right conditions, may form deposits there. These deposits then result in uneven heat fluxes.
Erosion. Solids in the water, and water in two-phase flow systems, can cause erosion at higher velocities.

Economizers and feedwater heaters:

Low-cycle fatigue. The impingement of cold water on hot surfaces, particularly during a quick shutdown and restart, sets up LCF.
Differential expansion. Uneven heating of tubes due to flow- or temperature-distribution problems can cause adjacent tubes to expand differently. Both compressive and tensile loads are imposed.
Deposits. Uneven or excessively fast ramp rates can result in solids precipitation and deposition, causing uneven heating.
Flow-accelerated corrosion. Single-phase FAC in economizers is being recognized as one cause of failures. Often it occurs because, during startups and at transition time, the water chemistry may be out of control.
Corrosion fatigue. Chemical imbalances can create corrosion, and cyclic loading can exacerbate the effect due to fatigue.
Erosion. Solids in the water can cause erosion at higher velocities.

Design needs dynamic analysis

In the design phase, the most important requirement is to make sure that all the factors affecting the life of the HRSG have been accounted for. This means that either the design features must be modified to mitigate the effect of the damaging factor, or the damaging factor must be eliminated. The most common way to ensure this is to do a life-cycle analysis, which typically consists of the following steps:

Define the basic operating conditions.
Establish the lifetime operating details.
Determine the most critical components.
Conduct a dynamic-response analysis of the critical components. This is perhaps the most critical factor in the life-cycle analysis. There are various software programs available that indicate the dynamic behavior of a component. However, these programs need to be custom-fitted to a given HRSG. To do this, the model has to be very well-defined. In addition, the expected operating conditions—such as pressure and temperature ramps that cause changes in the components—need to be defined thoroughly. Most of the life-cycle analyses currently on the commercial market do not give good results because of conservatism employed in the model. This often happens because the details of the component or the operating conditions are not worked out completely, and the model is not refined.
Calculate the cumulative damage factor (CDF). Various methods of calculating the CDF are available, including methods suggested by ASME, Germany’s TRD, and British Standards. It is important to use a consistent method rather than indiscriminately mixing various methods with different assumptions and data used in deriving the formulas.
Revise design or operating conditions if the CDF is higher than allowable.

Design features

Some of the specific design features that help in minimizing or monitoring the damage due to cycling are listed below. It is possible to design an HRSG without these features and still maintain the integrity of the boiler over the intended life of the unit. The key is to do a life-cycle analysis. If the life-cycle requirements are met with only some of these features, then the design should still be acceptable. Features that improve the cycling ability include these:

Smaller-diameter tubes, headers, and steam drums
Automated vents and drains
High-pressure superheater bypass to reheater
Wet reheaters
On-line water-chemistry monitors
Stack dampers
Leak-proof valves
Metal thermocouples
Minimization of piping and tube bends
Flexible connections
Motorized blowdowns
Economizer recirculation
No cascading blowdowns
External “kettle” boilers
Ability to clean
Spray coatings
Higher-grade metal alloys
Bypass dampers
Multiple attemperators
Good steam-/water-side flow distribution at all loads.

Operating practices

How the boiler is started up is a key factor affecting HRSG life. Rapid starting exacerbates fatigue, so it should be minimized, if it can’t be avoided altogether. The manufacturer-supplied start-up procedure may have some contingency built in, which can be analyzed and possibly removed. However, this is possible only if all the operating conditions, including the condition of the HRSG when starting and at shutdown, are well-defined.

After a “soak” period, which allows temperature differentials to be minimized, an HRSG can be ramped up or ramped down quickly. Ramping a running boiler is much faster than starting a new boiler. So it is advisable to ramp up the running unit and ramp down as the cold unit comes on-line.

Similar to ramping, load changes should be done gradually to minimize cycling effects. Often, HRSG manufacturers suggest making load changes in incremental steps rather than continuously. For example, instead of a continuous 10% change, the load may be changed in five 2% load changes with a dwell (or hold period) after each change.

Shutdowns by themselves may not be a big problem, unless purge requirements for the subsequent restart cause cold air to blow into a hot HRSG. Limitations on air flow should help minimize any damage.

The chemistry upsets and oxygen intrusion that frequently occur during HRSG layup substantially affect boiler life. When the boiler is put on-line, the heat will increase the damage.

Modifying existing units

Many of the HRSGs in service today were designed for baseload conditions but now are required to run as cycling units. Plant owners need to determine the impact that this will have on reliability and life expectancy. To do so, an engineering firm—preferably an HRSG manufacturer—should be retained to conduct a condition-assessment study, suggest equipment modifications that can extend service life, and implement a monitoring program to track damage mechanisms.

The condition assessment includes:

Identification of critical components and determination of their condition
Checking of instrumentation and controls
Review of operational history
Establishment of a baseline benchmark

Equipment modifications can be suggested after the proposed operations are defined by the owner and a complete life-cycle analysis of the critical components is performed. Sometimes a modification is feasible and cost-effective, but it may not be permitted because of code requirements.

A monitoring program should be implemented to track such variables as:

Temperatures, gas, water, and steam
Drum levels
Attemperator flows
Steam and water flows and velocities
Water chemistry
Steam purity and constituents
Gas-turbine and burner fuel
Exhaust-gas conditions

Data from the monitoring program should be reviewed and checked against the assumptions used in the equipment modifications. If there are any changes between the actual and initially specified operating conditions, these are noted and their effect on the life expectancy is assessed. Based on this assessment, some further adjustments may be necessary.

After at least a year of operation following equipment modifications, a condition assessment should be performed again, including measurement of wall thicknesses and concentrations of corrosion products and deposits. The assessment should include both destructive and nondestructive testing of suspect components, and all data should be checked against the baseline benchmark. Based on this assessment, additional equipment modifications or changes to operating conditions may be suggested.

Keep talkin’

For long service life of HRSGs, it is essential to have long-term cooperation and open exchange of information between the operators and the designers (see box). Both new and existing HRSGs can meet the rigors of cycling duty with the right design features, modifications to equipment, and adjustments in operating practices.

By Akber Pasha and Robert Allen, Vogt-NEM Inc

Edited by R.C. Swanekamp, PE

Oyster Creek Power 8, Freeport, Texas

japat30 — Mon, 23 Jun 2008 01:05:56 +0000

Operated and maintained by Dow Chemical Co., Freeport, Texas

Owned by Dynegy (50%) and American National Power (50%)

Sub-10 ppm NOx has been the dream of gas turbine users for many years, and currently there is only one OEM that can deliver on that promise. But OEMs are no longer the only suppliers of NOx retrofit hardware. Power Systems Manufacturing has developed a sub-5 ppm NOx retrofit kit for the GE 7EA that has taken dry low-NOx technology to the next level. Dow Chemical took a chance with the new technology and now operates the world’s cleanest—in terms of NOx—gas turbine.

By Troy Bearden and Curtis Banks, Dow Chemical Co.’s Texas Operations

Power 8 at Dow’s Oyster Creek site consists of three natural gas–fired GE Frame 7EAs and a 200-MW double extraction full condensing steam turbine originally commissioned between July and November 1994. The units are baseloaded and operate under power production contracts, although their primary use is to generate steam for Dow Chemical. The plant is capable of producing 440 MW. Dow supplies steam and power to the other plants at Oyster Creek and Plant A. Oyster Creek’s Power 8 is the newest of four powerhouses Dow operates at Freeport.

Oyster Creek Power 8 is not only the newest plant in the Dow Chemical fleet; it also has the lowest NOx emissions. The original dry low-NOx (DLN) 1.0 system ran about 12.6 ppm NOx and 3.3 ppm CO during normal operation at baseload. With the auxiliary duct burner–fired HRSGs, Power 8 is just barely going to make the NOx reductions required by state air pollution control authorities, assuming planned duct burner NOx reductions continue on schedule. The state NOx reduction plan requires a plantwide 80% reduction in NOx by 2008.

Lower NOx limits drove project

The project began over two and a half years ago when new Houston-area emission regulations were introduced to reduce NOx in incremental steps through 2008. For Dow, the lower limits meant it would have to make significant improvement in NOx reductions from its fleet of gas turbines and gas-fired HRSGs. After considering a variety of alternatives, Dow finally settled on standard selective catalytic reduction (SCR) with some form of ammonia injection. This approach was selected because the technology is well understood and has low technical risk. However, its installation and maintenance costs would be high, especially due to Power 8’s small site.

Power Systems Manufacturing (PSM) first began pitching its proprietary Low Emissions Combustor III (LEC III) early in 2001. But because the technology had no track record, the proposals didn’t get very far with Dow’s pragmatic operating staff. Dow’s refinery must operate reliably, and the possibility of any interruption of power and steam production was just too large a risk to take on an unproven technology.

In the meantime, PSM won a contract with TransAlta Cogeneration LP’s Fort Saskatchewan plant in Alberta, Canada. Fort Saskatchewan is a combined-cycle cogeneration plant that produces 120 MW of electricity and 100 tons/hr of process steam for a Dow Chemical facility. Prior to the turbine retrofit, the plant was having trouble getting NOx any lower than 17 ppm, and CO was fixed around 14 ppm. After installation of the LEC III system, EnTech Environmental certified 6-ppm NOx emissions and an average of 2.5 ppm of CO.

1. Low-emission combustor.

The first application of Power Systems Manufacturing’s low-emissions combustor on a 7EA turbine was at TransAlta Cogeneration LP’s Fort Saskatchewan plant in Alberta, Canada. Prior to the retrofit, the plant operated no lower than 17 ppm NOx and 14 ppm of CO. Afterwards, certified tests showed 6-ppm NOx emissions and an average of 2.5 ppm of CO.

Courtesy: OCL Limited Partnership

2. Quick change.

Retrofitting of the LEC components took only a few days. Installation of the LEC hardware began on March 20 and was piggybacked on other turbine repairs. The turbine was buttoned up on April 11 and started up the next morning.

Courtesy: OCL Limited Partnership

By the end of 2001, the replacement hardware was installed and producing 5.8-ppm dry NOx with no tweaking of fuel/air ratios. By September 2002, the hardware had run for 8,000 hours, maintaining 5.8 ppm NOx. A 24,000-hour major overhaul removed the hardware and returned it to PSM for refurbishment. Reinstallation is planned for September 2004. TransAlta was ecstatic not only about the results—the life increased to 16,000 hours of operation before refurbishment, compared with the 12,000-hour OEM limit—but also about the system’s 40% cost savings.

That was the kind of operating data that Dow needed to see to make a commitment to PSM for its LEC III technology. By January 2002, Dow invited PSM back for another sales pitch. This time PSM offered an 8-ppm guarantee for the simple reason that GE guarantees 9 ppm on the 7EA with DLN 1.0. Although the designs are significantly different in the way fuel and air are mixed prior to combustion; GE’s venturi in the liner is not 100% premix, whereas PSM’s low-emission combustor (LEC) is.

A deal was finally struck in November 2002 with several interesting requirements: the performance contract will include 8 ppm NOx as the guarantee point, but the design target will be 5 ppm, and PSM will work to reach that goal until both parties agree that no further reductions are practical. The schedule was tight; parts were due on the site on January 2 of this year. But because Dow requires that at least two of the three Frame 7EAs be operational at any time, other issues delayed the major outage until March 20, at which time the PSM hardware installation would be piggybacked on other planned major repairs. By April 8 the other repairs were completed and the LEC assemblies were installed. The turbine was buttoned up on April 11 and placed on turning gear that night, with startup scheduled for the morning.

Results count

Startup was uneventful, but the NOx readings caused quite a stir. Using default fuel splits of 81% primary/19% secondary, NOx readings were 6.75 ppm and CO was approximately 9 ppm at baseload power and 2,055ºF conditions. Tuning the splits over the next couple of days gave the engineers a better handle on the sensitivity of the system, and they arrived at a final split of 84%/16% with 4.75 ppm NOx and negligible CO using EPA-certified emissions test instruments within a week of initial installation of the LEC III—and meeting PSM’s design target of 5.0 ppm NOx.

This is an industry first for GE’s Frame 7EA turbine emissions control. Full turndown capability was maintained, and, at low part-load operation, the LEC system achieved emissions levels similar to baseload operation. Even more important, the performance of the LEC gave Dow the option to cancel the SCR, saving millions of dollars in capital costs and eliminating the complexity of an additional piece of hardware.

Dow Chemical Co.’s Curtis Banks says, “In the future, we intend to use PSM’s next-generation fuel nozzle technology and expect to see an additional 10% reduction in NOx, perhaps down to 4.2 ppm. I was also very impressed with PSM and its dedicated staff and the strict attention to detail displayed during the design and installation of this system. There was no extra down time associated with the LEC installation during our hot gas path inspection.”

Banks adds that, “as a matter of fact, I found out about PSM’s new LEC-III system by reading about it in POWER.” Perhaps that was the first step in Oyster Creek Power 8 becoming a Top Plant for 2003.

3. Low emissions.

Less than 5 ppm NOx and negligible CO using EPA-certified emissions test instruments were achieved within a week of initial installation of the LEC III at the Oyster Creek plant.

Courtesy: OCL Limited Partnership

4. Key staff.

Troy Bearden, Power 8 plant manager (left), and Curtis Banks, technical adviser for Dow Chemical’s Texas Operations (right), standing in Power 8’s control room. Power 8 is owned by the Oyster Creek Limited Partnership and is run and maintained by Dow Chemical. It is located at the Oyster Creek site of Dow Chemical’s Texas Operations in Freeport, Texas.

Courtesy: Dow Chemical