Hundreds of U.S. hydro plants come due for license renewal over the next decade, giving river and wildlife advocates an ideal time to push for fish-friendly turbine retrofits. With these new, e-”fish”-ent turbines, early retrofit projects have targeted up to 98% fish-passage efficiency and up to 15% more power output.

The 91,000 MW of hydropower capacity in the U.S. comes from about 180 federal projects and more than 2,000 non-federal projects regulated by the Federal Energy Regulatory Commission (FERC). Although the country has substantial undeveloped hydropower resources, little new construction is expected, and hydropower’s share of the nation’s generation is predicted to decline through 2020, due to a combination of environmental issues, regulatory pressures, and changes in energy economics.

FERC is the lead permitting agency for private hydroelectric plants. The U.S. Fish and Wildlife Service for the eastern part of the country, and the National Marine Fishery Service for the western part, are other agencies that make recommendations on fish mortality goals. In response to the 1986 Electric Consumers Protection Act, these agencies have set their target as “no fish production loss” for all new hydro projects as well as for any projects for which the hydraulic lease is expiring. That last phrase is key, because there are hundreds of plants in the U.S. that must pass through the relicensing minefield over the next decade. About 80% of California’s hydropower is subject to a FERC license, and about half of those facilities—approximately 4,000 MW at 150 projects—are due for license renewal in the next 15 years.

Save the fish

Turbines installed decades ago were designed with one thing in mind: maximizing power output. Although fish ladders were typically built for migratory fish, little thought was given to the side effects of fish injury and mortality caused by passage through the turbines or lower levels of dissolved oxygen in downstream water. Fish mortality rates currently range from 5% for the least-harmful existing turbines to more than 30% for more-damaging turbines.

Fortunately, special fish-friendly designs developed over the past decade have come into operation at several hydro power stations, significantly improving fish-passage efficiency while increasing power output. In fact, the repowering of projects built 50 years ago could eventually improve plant output by as much as 15%, thereby making a fish-friendly retrofit project economically feasible. The fish win, and so do plant owners and electric consumers.

Turbine-passage survival is a complicated function of gap sizes, runner blade angles, wicket gate openings and overhang, and water passageway flow patterns (see box). The consequence to fish populations of unaccommodating turbines is especially serious among migratory species—such as salmon, steelhead, and American shad—and eels that must pass downstream all the way to the sea, perhaps through multiple turbines, to complete their life cycle. That’s why increasing the passage efficiency of juvenile salmonids at Pacific Northwest hydro plants is one of the major challenges facing the industry. According to the Bonneville Power Authority (BPA), juvenile salmonids outmigrating to the Pacific Ocean through the Columbia River Basin during high spring flows experience a 5% to 25% mortality rate at each hydroelectric project they encounter. During this time, BPA—already teetering on the verge of bankruptcy and rising electricity costs—must reduce its power generation potential by $160 million per year through increased spills and other operations designed to increase fish-passage efficiency.

The U.S. Army Corps of Engineers operates eight multipurpose dams on the lower Columbia and Snake Rivers as part of the Federal Columbia River Power System. The Corps’ Columbia River Fish Mitigation program focuses on improving the passage of adult and juvenile salmon either around these dams with fish screens or through them with expensive fish-bypass structures. The Corps estimates that it will spend $1.4 billion implementing its fish-mitigation program, according to a 1998 report. About $908 million of this total will be spent on the construction of fish-passage projects and related studies from fiscal year 1999 through the scheduled completion of the program in fiscal year 2007, although currently shrinking budgets may place this goal in jeopardy.

New turbine designs arrive

The goal of the U.S. Department of Energy’s (DOE’s) Advanced Hydropower Turbine System (AHTS) program is to develop technology that will maximize the country’s hydropower resources while minimizing adverse environmental effects. The AHTS program is closely coordinated with industry and other stakeholders—such as Public Utility District No. 2 of Grant County (Washington), the Electric Power Research Institute, Corps of Engineers, U.S. Bureau of Reclamation, BPA, and National Marine Fishery Service—which all have a part to play in implementing advanced turbine designs.

The survival of turbine-passed fish depends greatly on characteristics of both the hydropower plant—the type and size of the turbine, environmental setting, and mode of operation—and the entrained fish—species, size, and physiological condition. Some small, Pelton-type turbines designed for high-head installations most likely cause complete mortality due to their basic design (Figure 2). On the other hand, the survival of small fish encountering turbine types with larger water passages—such as Kaplan, Francis, and bulb turbines—is commonly 70% or greater for current plants (Figure 3). Among the most fish-friendly conventional turbines, large Kaplan turbines used at the mainstem Columbia and Snake River dams have shown average fish survival (including both direct and indirect effects) of about 88% (Figure 4).

2. Pelton turbine: nearly 100% mortality

3. Kaplan turbine

4. Francis turbine

That’s why new fish-friendly turbine designs are a vital part of hydro’s future. The U.S. Department of Energy’s Advanced Hydropower Turbine System program has identified specific injury mechanisms, which include:

• Turbulent flows or cavitation in turbine water passages resulting from low-efficiency designs or plant operating strategies where extremely low water pressures cause the formation of vapor bubbles, which subsequently collapse violently.
  
• Turbulent flows and the trapping and cutting of fish in the zone of flow passing near the turbine hub when large gaps between blade and hub exist (characterizing the lower-output operation of Kaplan turbines).
  
• Strike of fish by turbine blades or impact of fish on structures including runner blades, stay vanes, wicket gates, and draft tube piers.
  
• Shear stress when two bodies of water of different velocities collide across a fish’s body. The highest values of shear stress are found close to the interface between the flow and solid objects it speeds by, such as the blade leading edges, vanes, and gates.
  
• Rapid and extreme pressure changes (water pressures within the turbine may increase to several times atmospheric pressure, then drop to sub-atmospheric pressure, all in a matter of seconds).
  
• Abrasion and grinding: Abrasion occurs with the rubbing action of a fish against rough turbine surfaces by flow turbulence and is dependent on flow discharge and velocity, number and spacing of turbine blades, and the geometry of flow passages. Grinding injury can occur when a fish is drawn into small clearances (gaps of sizes close to that of the fish) within the turbine system.
  

Testing of new designs with fish-friendly features has demonstrated even higher survival rates. The mission of the AHTS program has been to develop turbines that achieve 98% survival of turbine-passed fish.

Corkscrew turbine uncorked

The original AHTS design teams selected by the DOE in 1995 are still involved in bringing the fish-friendly designs to market. They are:

• Alden Research Laboratory (ARL, Holden, Mass.);
  
• Concepts NREC (White River Junction, Vt.), which was formed by the merger of Concepts ETI with Northern Research and Engineering Corp; and
  
• Voith Siemens Hydro Power Generation Inc (Heidenheim, Germany; U.S. office: York, Pa.) with team members Georgia Tech, Tennessee Valley Authority (TVA), MWH Consultants, and Normandeau Associates.
  

The latest ARL-designed runner (the “runner” in a hydro turbine is analogous to an impeller in a pump) uses only three long blades, which are wrapped around the central hub in a corkscrew shape to gradually reduce pressure and minimize blade-induced injuries. This is much different than the 6 to 10 blades found on most traditional hydro turbines. The new runner minimizes the number of blade leading edges, reduces the pressure-versus-time and the velocity- versus-distance gradients within the runner, minimizes clearance between the runner and runner housing, and maximizes the size of flow passages.

End result: Fish get more room in the water to swim through the turbine on their way to upstream spawning grounds or downstream to the ocean (Figure 5).

5. New runner: nearly 100% survival

Despite its dramatically different geometry, the new turbine has a predicted efficiency of only a few percentage points lower than a conventional turbine, although the power density is reduced. This means that, for modernizing a plant, the volume of the power house must increase to produce the same power output. For this reason the ARL design will focus on new installations. “The new fish-friendly turbine is expected to be used for new generation capacity, as replacements for existing turbines, and in fish-diversion systems installed near the main turbines,” says Thomas Cook, project manager for ARL. “We expect the cost of the new fish-friendly turbine to be comparable to existing hydraulic turbines.” Testing of a 2,000-hp full-scale model demonstrated control fish survival up to 99%, depending on fish size and turbine head. ARL has obtained patents for the new designs.

E-”fish”-ent turbines

For its contribution to the AHTS program, Voith Siemens Hydro (VSH) proposed building on the success of ongoing internal R&D programs and investigating the impact of existing turbine designs in relation to fish passage efficiency and developing new turbine designs that improve efficiency and reduce environmental effects for rehab projects. The results include design concepts for improved fish- passage survival in Kaplan and Francis turbines as well as designs for boosting dissolved oxygen levels in discharges from Francis turbines.

Elements of the advanced Kaplan designs were implemented in rehabilitated units recently installed at the Chelan County Public Utility District’s Rocky Reach powerplant, at the Corps of Engineers’ Bonneville Dam, and at the Tennessee Valley Authority’s (TVA’s) Kentucky Dam. An even more advanced design has been developed and model-tested for the Grant County Public Utility District’s Wanapum Dam. These fish-friendly designs generally focused on modifications to a Kaplan turbine that eliminated runner gaps, improved blade shapes, and included an advanced control system to sense the presence of fish and adjust to fish-friendly operation (Figure 6). Other major VSH design features that came out of the AHTS program include:

6. Advanced Kaplan design

• High efficiency over a wide operating range with reduced cavitation potential.
  
• A minimum gap runner (MGR) design, characterized as a design with a fully spherical discharge ring, no gap near the hub, and runner blades that tend to be thicker near the leading edge.
  
• A non-overhanging design for wicket gates.
  
• Environmentally compatible hydraulic fluid and lubricants, and greaseless wicket gate bushing.
  
• Smooth surface finishes in conjunction with upgrades for stay vanes, wicket gates, and draft tube cone.
  

VSH and the Georgia Institute of Technology are employing computational fluid dynamics (CFD) simulations of turbulent jets to better understand the fluid stresses that fish experience as they pass through hydroelectric turbines. VSH is using the same CFD model to relate measured velocity fields in an experimental flume used to expose fish to shear and turbulence to predicted velocity fields in a turbine at the Wanapum Dam on the Columbia River. Additional software (VSH’s “Virtual Fish” model) is being used to estimate flow-induced loads on both flume-passed and turbine-passed fish.

VSH has also developed several advanced computational tools for estimating trajectories of fish-like bodies passing through hydro turbines. The motion of the “virtual fish” is governed by a set of differential equations that account for the fish mass and various flow-induced forces. This model can be used not only to estimate the trajectory of a virtual fish from the forebay to the tailrace, but it also can provide specific information about a variety of flow-induced loads on fish passing through various zones of turbine flow.

Controls too

The fish stand to benefit both from new turbine designs and from new control systems for those turbines. For example, VSH and TVA jointly developed new controls to operate their fish-friendly hydro turbines. And Hydro Resource Solutions (Norris, Tenn.) markets “WaterView,” the state of the art in real-time hydro plant performance optimization when constrained by factors such as fish-passage criteria, civitation limits, avoidance zones, and ramp rates. For example, WaterView can:

• Limit turbine operation to fish-friendly modes when sensors indicate that fish are present and optimize plant performance whether fish are present or not.
  
• Streamline the periodic updates of Kaplan turbine “digital cam surfaces” to most efficient operation at each head and flow, minimizing fish-injuring flow turbulence.
  
• Sense active cavitation and limit turbine operation to noncavitating conditions.
  
• Optimize plant output when fish are present to achieve targeted fish-passage survival based on fish presence, location, turbine-passage mortality, spillway fish mortality, fish bypass characteristics, and total dissolved gas generated during spilling.
  

Bonneville Dam

The Corps of Engineers plans to install MGR on all 10 units at the Bonneville Powerhouse 1. The first units to be replaced were Unit 6—put into commercial operation on July 27, 1999—and Unit 4, which returned to service in September 1999. The remaining eight units will be rehabilitated at the rate of one per year through 2008.

The Corps conducted biological tests on Unit 6 after its retrofit to determine the unit’s ability to pass juvenile salmon safely. The survival of turbine-passed fish through Unit 6 was compared with the survival of fish passed through Unit 5, an adjacent, conventional Kaplan turbine. The goal of the biological testing was to determine if the MGR is at least equivalent to the existing machine in terms of fish-passage mortality. The biological tests, co-funded by the Corps, Grant County Public Utility District No. 2, DOE, and BPA, were conducted between November 1999 and January 2000 with a release of 7,200 balloon-tagged fish.

Overall injury rates among turbine-passed fish were impressively low for both units: 1.5% and 2.5% for the MGR and Kaplan unit, respectively. Survival rates of fish passing near the hub also were high (97% or greater) for both units, while survival rates for fish passing through the mid-blade region ranged from 95% to 97% and did not differ between units.

At all four power levels tested, the MGR showed better survival rates than the conventional Kaplan for fish that passed near the blade tip. Survival for blade tip–released fish ranged from 90.8% to 95.6% for the conventional Kaplan and from 93.8% to 97.5% for the MGR.

Chelan County is first

Public Utility District No. 1 of Chelan County in Washington State owns and operates the second-largest non-federal hydroelectric generating system in the U.S. The District’s three hydroelectric projects—Rocky Reach, Rock Island, and Lake Chelan—have a combined generating capacity of over 2,000 MW (Figure 7).

7. Rocky Reach plant

Rocky Reach Units 1 to 7, six-bladed vertical Kaplan turbines rated 140,000 hp, were built in the early 1960s by Allis Chalmers (now VSH). Turbines for the remaining Units 8 to 11, originally vertical propeller turbines rated 177,000 hp, were built in the early 1970s.

In the early 1990s, Units 1 to 7 began experiencing severe runner blade cracking, starting at the interface between the blades and the trunnions and progressing diagonally into the blade leaves. In June 1994, after completing a round of competitive model testing, the District awarded a contract for the rehabilitation of Units 1 through 7 to Voith Riva Hydro (now VSH).

While rehabilitation of Units 1 through 7 was moving forward, the rehabilitation of Units 8 to 11 became more pressing due to increased restrictions on unit operation to aid downstream fish passage. The VSH contract was amended to add turbine rehabilitation for Units 8 to 11.

During the model development phase, new ideas related to the safe passage of juvenile fish through the turbines were identified, building on the Bonneville Powerhouse 1 designs. VSH completed additional testing and model development based on the elimination of wedge-shaped gaps between runner blades and adjacent components and minimizing the runner hub-blade gaps upstream and downstream of the blade trunnion.

Also, a fully spherical discharge ring was developed for Units 8 through 11, closing the gap between the runner blade periphery and the discharge ring along the entire length of the blade. This elimination of the upstream blade-hub gap was later applied to all 11 Rocky Reach turbines, as well as other hydroelectric projects along the Columbia River, such as the Wanapum and Bonneville.

Rehabilitation of all 11 Rocky Reach units is scheduled for completion this spring.

Grant County advances

Last August, the DOE chose Washington State’s Grant County Public Utility District (PUD) to test a single fish-friendly turbine at its 1,038-MW Wanapum Dam on the Columbia River. “The new turbine is designed to allow salmon smolts to pass through the dam without injury,” says Stephen Brown, the PUD’s hydro engineering supervisor. But there’s also a nice side benefit: The proposed fish-friendly turbines are much more efficient than the existing turbines. The eventual uprating of all 10 Wanapum Dam units would provide an additional 300 MW of power to meet peak loads.

New advances in understanding the correlation between the turbine operation point and fish survivability can also contribute to improved operating efficiencies on the mainstem dams. Tests of the existing turbines at Wanapum Dam used balloon-tagged fish to verify many of the fish mortality mechanisms. These tests clearly demonstrated increased fish survival rates at increased flow rates (beyond the turbines’ “best-efficiency” points). The result: increased power generation and improved fish-passage survival.

These results counter the conventional hydro plant wisdom that says fish survival is reduced under conditions of very low operating efficiency. Fish-passage studies of Kaplan turbines at Lower Granite, Rocky Reach, and Wanapum Dams have all failed to detect a direct relationship between the “1% of peak turbine efficiency” target that is employed in the Columbia River basin and probability of highest survival.

“Our goal is to lessen injury on fish,” according to Brown. “We are looking for a 98% survival rate.” Brown said the federal government is picking up half of the $2.5-million engineering and biological testing cost. Grant PUD will cover the other $2.5 million, plus the cost of the turbine and installation, for a total of $14.5 million. The new turbine is scheduled for installation in late 2004, with testing set for spring 2005.

McNary Dam rehab

McNary Dam, at 7,265 ft long and 183 ft high—one of the largest hydroelectric power facilities in the U.S.—is among a succession of dams on the Columbia River between Oregon and Washington that must be navigated by salmon during their annual downstream migration to the ocean. After nearly 50 years of constant use, the turbines at McNary Dam are being studied by the BPA and the Corps of Engineers for total replacement during a 13-year powerhouse overhaul. In June 2002, four contracts were awarded to firms specializing in manufacturing large hydroelectric turbines:

• VSH;
  
• Alstom Power (Littleton, Colo.);
  
• G.E. Hydro Power (Pleasanton, Calif.); and
  
• VA Tech Voest MCE (Charlotte, N.C.).
  

Each of these firms will design, build, and test scale models of a new turbine they would propose to install at McNary. The full-size turbine will be subjected to in-stream biological testing and evaluated for both fish survival and hydraulic performance. The test results will be incorporated as part of the National Environmental Policy Act analysis required for the rehab permit.

“The outcome of the testing, analysis, and the public input process could lead to a federal decision to replace all 14 of the existing 80-MW Kaplan turbines,” said Kevin Crum, project manager for the Corps of Engineers.

Fish gotta breathe too

Mechanical injury is not the only fish- damaging aspect of hydro turbines. Dissolved oxygen (DO) levels downstream of a powerhouse tend to drop during warm months, effectively suffocating fish that had successfully passed through the turbines. This is a particular problem in the U.S. Southeast.

In the 1980s, VSH and TVA invested in a joint research partnership to enhance DO concentrations in releases from Francis-type turbines. “Auto-venting” (AVT), or “self-aerating” turbines, which use the low pressures created by flows entering the turbine to induce additional airflows, typically are the most cost-effective technologies for Francis turbines (Figure 8).

8. Adding air to water

In the last 10 years, significant progress has been made. TVA has developed reliable line diffuser technologies and surface-water pumps for low-cost aeration of reservoirs upstream of hydro plants and effective labyrinth weirs and infuser weirs for aerating downstream flows.

TVA’s Norris Dam was selected as the first site to demonstrate the AVT technologies. The two Norris AVTs have specially shaped turbine component geometries developed to enhance low pressures at locations for aeration outlets in the turbine water passage, to draw air into an efficiently absorbed bubble cloud, and to minimize aeration auxiliary power. Results show that up to 5.5 mg/l of additional DO uptake can be obtained for single-unit operation with all aeration options operating. In this case, the amount of air aspirated by the turbine is more than twice that obtained in the original turbines with hub baffles. Compared to the original turbines at the plant, these specially designed replacement units increased overall efficiency 3.5% and increased capacity by 10%. The new runners also have shown significant reductions in both cavitation and vibration.

The first uprated and rehabilitated AVT was recently returned to service at the Corps of Engineers’ J. Strom Thurmond plant in Clarks Hill, South Carolina. The 48-yr-old plant—yes, it was named for the ageless senator that long ago—is being upgraded with Francis runners designed to increase the levels of DO in rivers with depleted or diminished gas content. Seasonal stratifications result in the discharge of water with less than 1 mg/l DO during the summer months as far as 16 miles downstream from the dam. Georgia and South Carolina have a standard of 5 mg/l for that portion of the Savannah River.

The modified Francis turbine design includes fewer blades, improved blade shapes, and larger spaces between blades that improve fish-passage survival as well. Initial tests last September of the first installed unit showed DO improvement of slightly more than 4.0 mg/l with minimal impact on turbine efficiency.

The first of seven new aerating turbines arrived at J. Strom Thurmond in March 2002. The second turbine is due to arrive March 2003, and by 2006 all seven should be installed and operating.

By Dr. Robert Peltier, PE, Sr. Editor

Oil condition data published in 2001 makes reference to the first application of this technology on steam-turbine lube oil. The research trial ran for more than five years and concluded that the lube oil tested at 16 times cleaner than new oil specifications (Figure 1). The technique essentially supercharges the filtration process by electronically removing sub-micron material and products of oxidation together, for removal by standard and proprietary filters.

1. Close-up of a compressor bearing

This process also can be applied to high-voltage transformer fluid, where it can increase the dielectric resistance of insulating fluids to better-than-new standards. In fact, recent studies suggest that particulate contamination may be as significant as water contamination in reducing the reliability of transformers and tap changers. As effective as water removal is in improving electrical resistance, removing these fine particles boosts dielectric strength even higher and blocks the pre-varnish discoloration that often is seen forming in tap-changer oil and on the contacts. During a typical on-line clean-up cycle, transformer oil was restored from 20 kV to 75 kV, preventing transformer downtime and improving equipment performance.

During a typical clean-up of transformer fluid for an industrial environment, particle count was reduced to such a low level that the dielectric strength was improved from 35 to 90 kV. This increase in kV resistance is much better than new oil specs, with the net result that the useful life of the oil is dramatically extended. Using a combination of the fluid technology process to remove sub-micron material together with a vacuum distillation process to reduce water contents to below 10 ppm and gas to less than 0.08% by volume results in fluid that has the maximum kV value attainable (Figure 2).

2. Extending oil life

From hydraulic fluid at a major auto parts manufacturer to tap-changer switchgear, turbines, and compressors, dramatic reductions in particulates and the products of oxidation have documented the effectiveness of the BCA process. The process induces reformation of varnish within a fluid-collection cartridge, depositing varnish and sludge onto the proprietary depth media cartridge. Previous early indicators of films forming on switchgear in tap changers does not appear in the BCA-protected apparatus.

Recently, a new system incorporating a low-maintenance PetroTech vacuum dehydrator was installed at a major utility site in the Northeast. In addition to the significantly reduced particle counts, water and gas quickly dropped to extremely low levels (Figure 3). The proven ability to address all aspects of transformer oil condition using one cost-effective portable system has motivated ISOPUR Fluid Technology Inc (Rocky Hill, Conn.) to design smaller, permanent units with remote monitoring capabilities for installation on critical or troubled (high-maintenance) equipment.

3. PetroTech vacuum dehydrator

Standard mechanical filtration can remove larger particles but has no impact on the millions of smaller particulate matter that can easily pass through the filter and accumulate in critical equipment. These small particles pick up a low uniform static charge, causing the formation of varnish and sludge due to their attraction to grounded internal surfaces. The BCA process can gather together particles below the one-tenth micron size and remove them from the fluid. Because most soot particles range from one-tenth to three-tenths micron, the normal drop in kV resistance over time is eliminated. By creating floods of equal and opposite-charged particles, the BCA process eliminates net static charge and blocks varnish formation.

Essentially, the varnish that normally forms in machines plates out in the fluid-collection cartridge due to the BCA process. Because the spaces in the collection cartridge range from 50 to 300 microns, a large amount of sub-micron material and products of oxidation can be collected before change-out is required. A typical cartridge life is one year. Typical fluid life is expected to be measured in decades, even with troubled systems.

By Gerald Munson and C. Wesley Mitchell, ISOPUR Fluid Technology, and R. Haig Hachadoorian, Petroleum Technology Inc

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

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

3. Dry low-emission (DLE) fuel injectors

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 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

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

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 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

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 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

2. Niederaussem, Cologne, Germany

The Niederaussem Unit K is a supercritical boiler with a boiler efficiency of almost 95% (LHV) with steam pressure of approximately 3,988 psig and steam temperatures of 1,076F. The plant electrical efficiency is over 43% (LHV). Alstom (Paris, France) was the consortium leader for the engineering, construction, and commissioning of the steam generator. The unit’s owner is RWE Rheinbraun AG (Essen, Germany).

Hammerfest, Norway, with 11,000 inhabitants, calls itself the world’s northernmost town. In December, tidal currents started turning the blades of a windmill-like turbine standing on the seabed near Kvalsund at the Arctic tip of the country. “We will be the first in the world to use tidal currents to generate electricity to be fed into the local grid,” said Harald Johansen, managing director of Hammerfest Stroem (Oslo, Norway).

Hammerfest Stroem uses proprietary water “wind mill” technology to convert the kinetic energy in a tidal current into electricity. In Kvalsund, the water flows at about 7.5 feet per second, apart from a pause at high and low tides. The 300-kW tidal stream turbine with 45- to 48-ft long blades is mounted on 200-ton towers placed on the seabed. The turbine automatically turns to face the tide when the currents change direction, and the propeller blades automatically adjust to their optimum orientation in the prevailing current (Figure 3).

3. Hammerfest Stroem, Norway

Johansen reckons the project has cost $6.7 million so far and will cost almost $15 million to complete installation of all 20 turbines by 2004. The production cost of the electricity is estimated to be 4.3 to 5 cents/kWh, three times that of typical hydro-generated electricity in Norway. Tidal power will be added to the mix of electricity in the local grid, and consumers will be required to absorb the cost.

The biggest tidal powerplant in the world is on the La Rance River in northern France and has been in place since the 1960s. It has a 240-MW capacity, but Electricité de France has no plans to build new ones. Canada’s Bay of Fundy in Nova Scotia has the highest tides in the world, at about 39 ft. Nova Scotia Power’s 20-MW plant at Annapolis Royal, built in 1984, is the only one in North America; the company is focusing more on wind.

Experts are uncertain about the potential of tidal power, especially because of sub-sea maintenance costs. Storms have wrecked many experimental ocean-power stations.

The British firm Marine Current Turbines, which plans to test a similar tidal current system off Devon in southern England next year, says that maintenance could be a problem for Hammerfest. “When you have strong enough currents for tidal-energy generation, there are few slack tides when divers can work,” said Peter Fraenkel, the group’s technical director.