Issue 6 and Volume 102.


By Brian K. Schimmoller, Associate Editor

Asset managers can select from a variety of retrofit options to best position their plants for long-term mechanical reliability and competitive generation.

The Energy Information Admini stration predicts that 403 GW of new electric capacity will be needed in the United States by 2020 to meet growing demand and replace retired capacity.1 This prediction bodes well for the industry as a whole, and for plant designers, financiers and constructors in particular. Undoubtedly, however, the bulk of that new capacity will come on-line closer to 2020 than 2000, meaning more and more pressure on aging plants to maintain mechanical viability in the near term. The turbulent forces of deregulation/restructuring multiply the pressures, forcing plant operators to squeeze every extra MW and every fractional efficiency gain out of their units to remain profitable and competitive in the dispatch order. Retrofits–the addition, upgrading or replacement of equipment in existing power plants–provide a relief mechanism for these stresses.

Most retrofits can be pigeonholed into one of two categories: those that have to be done to keep the plant operational and those that have to be done to improve the plant`s competitive position. In the first category are projects such as emissions control equipment installations and safety renovations. In the second category are projects such as steam- and gas-path upgrades to increase capacity, boiler-fuel conversion retrofits to reduce fuel costs, and advanced control systems to boost plant efficiency. Such a categorical separation, however, overlooks the fact that power plant asset managers are making greater use of life cycle cost projections and are willing to shut units down for competitive reasons–even if there is no purely mechanical justification. In this respect, all retrofits represent a calculated response to emerging open competition, positioning each unit to effectively respond to market demand.

Taking Control

Control system upgrades have long been a staple of the power plant retrofit business. As old systems aged and became obsolete, digital technology, accessorized with the latest bells and whistles, took their place. Today, as plant operators evaluate their assets with an eye toward open competition–deciding which units are keepers and which units should just be run into the ground–control retrofits require more justification. Because of their relatively short paybacks, however, control retrofits are often quite attractive and offer cost-saving opportunities with respect to labor, fuel, maintenance, emissions and plant flexibility.

Detroit Edison meets a large portion of its power demand requirements from the 3,000 MW Monroe Generating Station. This four-unit, coal-fired plant relies on once-through supercritical boilers for steam generation. After an internal asset evaluation tagged Monroe as a “keeper” plant–worthy of long-term investment–Detroit Edison began investigating a distributed control system (DCS) upgrade to improve each unit`s operational efficiency. Without any previous experience in the specification, design or operation of DCSs, Detroit Edison decided to accelerate the learning curve for the selected control system using a PC-based simulator. The Bailey simulator uses actual plant logic running the same type of processors as in the plant and incorporating the same type of operator consoles and graphics. “The simulator allowed Detroit Edison to learn what it liked and didn`t like so the operators would be comfortable and proficient when the new system went on-line,” said Don Frerichs, Bailey`s director of applications research. After nine months of simulator trials, an INFI 90 OPEN DCS was installed on Monroe`s Unit 4, consisting of approximately 5,000 field input/output points, 12 process control units and 56 multi-function processors housed in 39 cabinets. The remaining three units at Monroe have, or will have, new control systems in place and operational by mid-1999.

Control system upgrades can also provide fuel savings. At gas-fired power plants, where fuel costs can account for more than 70 percent of operating costs, maximizing the purchase of lower-priced gas can pay large dividends. Plant operators, constrained by a single delivery pipeline, can install multiple pipelines to accommodate commodity trading. A DCS tying the pipelines to the plant can then weigh fuel demand at the plant against the price and availability of gas in the pipelines to minimize fuel costs. Excess gas can be sold on the wholesale market.

The technical sophistication of control systems mitigates against the significant reuse of existing equipment during a controls retrofit. Simply put, new digital transmitters are used because they`re that much better than pneumatic and analog devices. Nonetheless, reuse can provide cost-saving alternatives. Valves and actuators can be reconditioned or upgraded. Electrical cabinet enclosures can be reused. And rather than incurring high labor costs to install wiring, existing wiring can often be reused to accommodate the 2,000 to 3,000 inputs in a large plant. Control room consolidation also offers retrofit advantages. “At one northeast plant, consolidating four boiler control rooms into one reduced the number of operators by 13 per shift,” said Harold Sternberg, Bailey`s manager of power generation marketing. Power plants are also investigating the possibility of using a single control room to operate and monitor multiple sites. This is already done at offshore oil platforms, and with the escalating capabilities and reliability of telecommunication devices, adaptation to power plant operation is not a question of if, but when.

Control retrofits are popular today because they often provide extremely short payback periods. Unlike major turbine or boiler retrofits, where capital expenses in the tens to hundreds of million dollars dictate extended payback periods, controls retrofits on the order of $2 to $3 million can be paid back in less than a year in some cases. Controls retrofits also benefit from the ability to take credit for more cost savings than were previously allowed. Public utility commissions typically required that fuel cost savings, for example, be passed on to the customer, reducing any upgrade incentive. Turndown is another benefit that couldn`t previously be claimed. Today, the installation of a control system enables plants to be turned down more efficiently, freeing utilities to run more-efficient units harder. Bailey reports that one southern utility justified a control system retrofit simply on the basis of the improved turndown and subsequent unit flexibility. By trimming a 525 MW coal-fired power plant`s output during low demand periods, the utility could maintain its nuclear plants at, or near, full load. The benefits of stable nuclear operation and dispatch outweighed the coal unit`s revenue loss. The DCS at the coal plant accommodates part-load operation more effectively than previous operator-dependent analog systems, enabling cost-effective operation.


The Lennox Generating Station on Lake Ontario, owned and operated by Ontario Hydro, consists of four 550 MW oil-fired generating units. At various times since being placed in service in 1976, the units have been mothballed because of high operating costs. To reduce generation costs–and take advantage of seasonal fuel price differentials between residual oil and natural gas–Ontario Hydro decided to retrofit Units 1 and 2 with dual fuel capabilities. Outages in the fall of 1998 will accommodate a December 1, 1998 return to service.

According to Ken Jobba, project manager at Lennox, the two units will be capable of firing oil and gas simultaneously. Each boiler contains four elevations of eight burners. After the retrofit, each burner elevation will be able to fire entirely on oil or entirely on gas, increasing the unit`s operational flexibility by permitting various fuel firing combinations. The following physical changes will be necessary for the $11 million retrofit project:

Addition of gas spuds in the fuel air nozzles above and below each oil burner,

Opening of additional auxiliary air nozzles that were originally blanked off,

Installation of new flame scanners for sighting both oil and gas flames,

Addition of combustion controls for gas firing,

Replacement of the burner management system,

Installation of natural gas flow control stations and distribution piping to each burner, and

Installation of natural gas supply piping and a pressure reducing station downstream of the metering station.

Ontario Hydro has contracted with ABB for burner modifications, distribution piping and flame scanners; with Foxboro for combustion controls and burner management system; and with Union Gas for a 10-mile pipeline and metering station from the main TransCanada pipeline between Toronto and Montreal.

The conversion project does not include any pressure part modifications, so no impact is expected on existing steam conditions or turbine rating. However, it is anticipated that burner tilts will be set to their lower position and both superheat and reheat attemperation will be used at full load when firing natural gas. Boiler efficiency is expected to be reduced by about 5 percent with full-load gas firing; SO2 emissions will be virtually eliminated and NOx emissions reduced 20 to 30 percent.

The main rationale for the project is the expected economic benefit achieved through fuel cost savings. The plant will operate primarily on natural gas during the residential non-heating season to take advantage of lower gas prices, while continuing to operate primarily on oil during the heating season. The plant will be dispatched as a peaking unit, but at higher capacity factors than in recent years.

Front to Back

An evolving retrofit approach focuses on integrated plant improvement. By teaming boiler OEMs with turbine OEMs, and calling in architect/engineer (AE) firms for balance-of-plant expertise as necessary, a holistic analysis can be conducted that provides maximum plant benefit rather than individual component benefit. This approach recognizes the reality that low-cost generation is mandatory; without high reliability, however, low-cost generation is insufficient to guarantee profitability. As the figure shows, a large fossil-fired power plant will generate more than 70 percent of its annual margin contribution in just three months of the year. If a unit experiences a forced outage during a peak season, profitable operation for that year is unlikely.

The primary driver for retrofits in an open market is a unit`s projected duty cycle. Because of the constraints of the traditional power generation industry, power generators operating in this venue can only sell power within their specified territorial boundaries. Low-cost generating units, therefore, are not fully dispatched because of limited market. Such units will be most interested in improving and maintaining high unit reliability and increasing their MW output to maximize revenues. Heat rate improvement will always be important from the standpoint of reducing fuel cost, but for these low-cost units, that objective will be secondary to maximizing capacity and reliability. Conversely, for units that are projected to have low capacity factors because of high production costs, programs to lower their overall production cost will be paramount. Since fuel makes up approximately 85 percent of a unit`s variable production cost, heat rate improvements will be very important, moving the unit up in the dispatch order and increasing its profitability.

Westinghouse`s Power Plant Modernization (PPM) program places greater emphasis on integrated overall plant improvements with the goal of improving performance and reliability while simultaneously offering modernization and life extension. Through alliance agreements with Babcock & Wilcox, DB Riley and Foster Wheeler for the boilers, and AEs such as Stone & Webster, Westinghouse is able to provide, in most cases, original equipment manufacturer expertise on the turbine-generator and boiler to address the customer`s specific needs. According to Candido Veiga, manager of PPM, “significant performance and environmental benefits can be achieved by simply modernizing the total potential of the boiler and turbine. In many cases, the boilers have as much as 10 percent additional capability that the turbine was not originally designed to handle because either the boiler and turbine cycles were not properly matched or because of technology limitations at the time of the original design.”

In 1995, Omaha Public Power District (OPPD) was investigating the operating benefits of replacing turbine rotors. Originally, OPPD believed that the biggest benefit could be realized from replacing the LP turbine rotors. Discussions with Westinghouse, however, revealed that greater benefits could be realized by replacing the HP/IP turbine rotor and performing a broader total plant modernization which would address OPPD`s pressing need for increased plant efficiency and capacity. Westinghouse teamed with DB Riley to provide a package of boiler, turbine and balance-of-plant modifications. The existing boiler met the design steam flow ratings, but suffered from low main and reheat steam temperatures, often falling from 1,000 F to 970 F. Surface area additions enabled the necessary steam flow to be achieved at the design temperatures. A new HP/IP rotor with a monoblock forging and optimized blade path was the primary scope on the turbine. The project team re-evaluated the generator and put it through a series of electrical tests, resulting in a nameplate uprating from 686 MVA to 723 MVA. The contract guaranteed 35 MW above the previous maximum continuous rating of 616 MW; post-retrofit ASME performance testing has been completed and revealed a current maximum plant capability of 664 MW.

The latest addition to the Westinghouse total plant modernization strategy is creative project financing approaches. For example, Westinghouse recently teamed with Constellation Power Source (CPS) on a plant upgrade contract in the western United States. Westinghouse will design and implement a plant upgrade that guarantees a 32 MW capacity increase; CPS will market the additional 32 MW for a period of five years and pay for the upgrade through the power sales. The customer gets all the benefits of improved efficiency and reliability without any up front capital expenditure, and at the end of the five-year power purchase contract they retain ownership of the 32 MW.

Propping the Grid

In addition to responding to the uncertainties associated with industry deregulation, electricity generators also must deal with changing end-use load profiles that can upset power factor on the grid and require system support. One way to combat low power factor–and potentially increase unit utilization–is to operate generators as synchronous condensers. A rotating synchronous condenser is a synchronous machine, connected to an electrical system, that can be driven by the system and can supply or absorb reactive power. All that is required is a means of accelerating the generator to synchronous speed and then detaching the prime mover (if part of the system) from the generator after achieving electrical synchronization.

Commonwealth Edison`s Zion Nuclear Station, which was shut down by the Nuclear Regulatory Commission in 1997, has decommissioned its two steam turbine trains. Rather than idle its entire investment, however, ComEd contracted with Westinghouse to retrofit the two 1,100 MW generators with acceleration packages to operate them as synchronous condensers. According to Randall Attix, senior applications engineer for SSS Clutch Company Ltd., the acceleration packages consist of a 6 MW TECO electric motor, a Voith torque converter and a synchronous self-shifting clutch from SSS Clutch. When the units return to operation in June 1998 and June 1999, they will each produce 825 MVARs for the grid at 1,800 rpm.

Synchronous condensers are not limited in application to large units. City Electric System, which serves the lower Florida Keys (including Key West), recognized the benefit of additional VARs to enable more power to be transmitted along the two 138 kVA power lines that connect the Keys to mainland Florida. GE retrofitted an acceleration package into a 44.8 MVA generator to provide 34.1 MVAR lagging and 22.5 MVAR leading power to help stabilize system voltage.2 City Electric System also took advantage of combined turbine/generator clutched arrangements. By fitting a synchronous self-shifting clutch between the turbine and generator, a unit can be operated as a conventional power source (with turbine connected) or as a synchronous condenser (turbine disconnected). Two GE 20 MW Frame 5000 turbines are being installed on Stock Island for re-commissioning in June 1998. One will have a clutch retrofitted into the load gearbox between the turbine and generator; the other will be equipped for possible clutch retrofit as conditions dictate.

Retrofitting clutches into existing turbine-generator plants can be complicated by space limitations between the turbine and the generator. In most instances, movement of either the turbine or generator is required to accommodate the clutch. For this reason, incorporation of synchronous self-shifting clutches into the original unit design–or reserving space for future installation–is preferred. With the proliferation of combustion turbine generation systems, allowing for synchronous condensing operation is gaining popularity because of the substantial flexibility it provides. For example, the Siemens V84.3A gas turbine at Kansas City Power & Light`s Hawthorn Power Station is believed to be the first U.S.-installed heavy-duty gas turbine equipped with a synchronous clutch to provide grid support when power is not needed. p

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The Lennox Generating Station is being retrofit with equipment that will accommodate dual firing of oil and gas. Photo courtesy of Ontario Hydro.

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Close-up of the synchronous self-shifting clutch and acceleration package retrofitted into B.C. Hydro`s oil-fired Burrard Station. Photo courtesy of SSS Clutch Company Inc.


1 Energy Information Administration, Annual Energy Outlook 1998, Document No. DOE/EIA-0383(98), December 1997, p. 51.

2 Gerstenkorn, D. and Hendry, M.L., “Improving Transmission System Efficiency Using a Synchronous Condenser,” Florida Municipal Electric Association`s Energy Connections Workshop, Orlando, Fla., 1997.

Artificial intelligence is making inroads at power generating plants. Neural network-based boiler optimization technologies can offer substantial improvements in efficiency, emissions, operating costs and unit flexibility. By using operational data obtained during periods of best unit performance, optimal operation setpoints can be “learned” by the neural network. Pegasus Technologies Ltd.`s NeuSIGHT software provides NOx emissions reductions of 15 to 60 percent, heat rate reductions of 0.5to 5.0 percent andloss-on-ignition reductions of up to 30 percent. NeuCo LLC`s ProcessLink system, in use at Canal Electric Company`s Unit 2, boosted output by 20 MW, reduced carbon monoxide emissions between 20 and 40 percent and reduced NOx emissions by 10 to 50 percent. The utility is expected to save $2 million annually with the system. NeuCo recently formed an alliance with DB Riley Inc.to jointly marketthe technology tofossil-fired boilers.