Colorado Cogen Beats the Heat

Issue 6 and Volume 103.

A July 1998 Heat Wave across Colorado Stretched Power Supplies Almost to Their Breaking Point, resulting in short-term blackouts and calls for energy use curtailment. With several power plants suffering unplanned outages, the state`s utilities asked its wholesale power producers to increase their output to make up for the shortage. Public Service Company of Colorado (PSCo), for example, ended up buying at least twice as much wholesale electricity as usual during the heat wave.

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The Ft. Lupton combined-cycle cogeneration plant northeast of Denver, a qualifying facility jointly owned by CSW Energy and Thermo Cogeneration Partnership, occupies a unique niche in Colorado`s electricity supply network. Relatively large by cogeneration standards at 272 MW, Ft. Lupton represents a key swing component of PSCo`s strategy for meeting the Denver area`s growing loads. Plant operation is also critical to the operations of the adjacent 40-acre tomato greenhouses.

Ft. Lupton is a five-unit combined-cycle plant based on the GE LM6000 gas turbine. Originally designed for two separate sites, the project developers reconfigured and delayed plant construction until 1994 to accommodate PSCo resource planning efforts. The eventual single-site design is split into two relatively independent plants-a 2×1 combined cycle producing 122 MW and a 3×1 combined cycle producing 150 MW-although much of the balance-of-plant equipment is shared between the two systems.

PSCo dispatches Ft. Lupton through its Lookout Mountain control center. PSCo relies on Ft. Lupton to make up for lost power during plant outages (scheduled or forced) and to provide extra power during extreme weather episodes. At 60 percent load, control shifts from GE Energy Plant Operations (which operates and maintains the plant) to PSCo using automatic generation control (AGC). A 2 percent per minute capacity ramp rate is permissible. Because of the five-unit configuration, load response is inherently flexible. The plant offers about a 200 MW capacity supply window, extending up to 272 MW, providing grid power at competitive heat rates ranging from 7,800 Btu/kWh (higher heating value) to 10,000 Btu/kWh.

Plant Layout

The gas turbines (split three and two) and associated heat recovery steam generators (HRSGs) and stacks straddle a two-unit steam turbine room. The common cooling towers, water treatment system, chiller equipment, raw water tanks and cooling water pumps are housed separately, south of the turbine buildings.

The five LM6000 units are permitted for 25 ppm NOx emissions. Using 600 psi attemperated, superheated steam drawn from the high-pressure section of the HRSG, NOx emissions are controlled to 22 ppm. Fluctuating weather conditions in the area make it difficult to achieve the gas turbines` design inlet air temperature of 47 F. Three cooling systems are available, therefore, to reduce inlet air temperatures and boost power output as necessary. Spray cooling maintains acceptable gas turbine performance between 47 and 75 F (compressor inlet temperature). Above 75 F, evaporative cooling and/or mechanical chilling must be applied to sustain power output. Mechanical chilling is provided by an 1,100-ton natural gas-fired liquid bromide chiller. It is important to realize that neither chilling nor cooling can achieve ideal compressor inlet temperatures under every circumstance.

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GE did much of the testwork for its SPRINT inlet air cooling technology on Ft. Lupton`s LM6000 units. Ft. Lupton provided an excellent host site because the plant is not a summer peaking facility, allowing individual units to be evaluated without significant impact on total plant output. The SPRINT technology involves deionized water injection into the gas turbine to increase mass flow rate and boost output. Although the LM6000PA units installed at Ft. Lupton would not be able to take full advantage of the SPRINT system at full load (because the PA models are mass flow limited), they successfully demonstrated the technical concept and validated the 10 to 15 percent power augmentation that will be possible in GE`s LM6000PC units.

Gas turbine exhaust at 825-875 F from each LM6000 feeds a two-pressure HRSG equipped with gas-fired duct burners. High-pressure steam is produced at 600 psi and 750 F; low-pressure steam is produced at 30 psi. Two axial-exhaust ABB steam turbines, each rated at 52.2 MW with no extraction, complete the plant`s combined cycle. Steam flow through the two condensers and deaerators makes feedwater available to the gas turbines` HRSGs.

When the Ft. Lupton plant first went on-line, load control was accomplished through duct burner firing in conjunction with operator manipulation of the gas turbines. A recent logic upgrade has enabled better control integration between the gas turbine and steam turbine systems. When PSCo calls for additional power, the gas turbines respond first (until temperature or pressure limits are reached), thereby reducing the duct firing rate and increasing plant efficiency. Conversely, when PSCo reduces demand, the steam turbines shed load until a predetermined limit is met before the gas turbines begin dropping load. Considering that the duct burner`s heat rate is 13,000 Btu/kWh versus 8,000 Btu/kWh for the gas turbine, primary load control based on the gas turbine is obviously justified.

Maintenance and upkeep of the water treatment system is outsourced to a local service company. Boiler water quality is achieved through a two-stage reverse osmosis unit and an ion exchange system to reduce conductivity. Bleach is added for oxidation. A separate reverse osmosis system controls the quality of water used for irrigation at the adjacent greenhouse complex. Water supply for cooling tower makeup, HRSG makeup, gas turbine steam injection and greenhouse use is provided by the city of Ft. Lupton. Wastewater treatment is provided by the local POTW (publicly owned treatment works). The intertie between the plant and the POTW includes a surge-containment pond to limit plant discharges during peak city usage.

The adjacent tomato greenhouses can use up to four products from the Ft. Lupton plant depending on weather conditions and facility requirements:

  • Hot water for heating needs at the greenhouse is supplied at 215 F through a closed-loop system tied to a heat exchanger in the Ft. Lupton power plant.

  • Natural gas at 120 psi is supplied to the greenhouse complex from the power plant low-pressure gas header. The natural gas is used to fuel boilers in the greenhouse, providing heat and enabling CO2 to be harvested from the boiler stack gas to “feed” the tomato plants.

  • High-quality water for tomato plant irrigation is generated by the power plant`s reverse osmosis unit.

  • Raw water is piped from the power plant to the greenhouse for roof cooling control as necessary. The greenhouse softens the water prior to application.

    Currently, the greenhouse facility does not draw electricity directly from the plant.

    Location, location, location

    The Ft. Lupton plant is situated on prime real estate, strategically positioned at the site of a major 230 kV interconnection and multiple natural gas pipelines. Electricity generated from the gas turbines and steam turbines at 13.8 kV is stepped up on site to PSCo`s 230 kV network interconnection. As the state`s single-largest consumer of natural gas, the Ft. Lupton plant significantly benefits from the availability of multiple gas pipelines, which enable it to source plant fuel from four transporters and 12 suppliers.

    The natural gas supply infrastructure features a unique microwave transmitter system. Natural gas traders for GE Energy Plant Operations can access quantity, supplier and transporter data in real time to analyze historical trends and assist in making future purchases. Through periodic sampling of delivered natural gas, the plant is also able to base its payments to gas suppliers on Btu content rather than volume, thereby safeguarding against quality fluctuations. According to Richard Rhoads, assistant plant manager at Ft. Lupton, although some suppliers have insisted on independent verification or sampling oversight, the practice has been well received.

    Although no firm plans exist, there is opportunity for future expansion of the Ft. Lupton facility. The controlling partnership owns additional property adjacent to the plant, which could be developed separately or possibly tied into the existing infrastructure.

    Operating History

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    In its four years of operation, the Ft. Lupton plant has demonstrated excellent reliability at competitive costs, even as PSCo has increased its dispatch. Capacity factor has risen from 40 percent in year 1, to 50 percent in year 2, to 60 percent in years 3 and 4, the level where economic return is most favorable. “Current operating costs are a shade over 2 cents per kWh, achieved with a consistent plant reliability in the 98.5 to 99.8 percent range,” said Rhoads. The only major mechanical failure has been the loss of a turbine blade early in the plant`s lifetime; fortunately, the blade was from the fifth-stage LP turbine row and didn`t cause significant damage.

    The LM6000 gas turbines have been particularly reliable. Major inspection and overhaul functions were not necessary until the 25,000 hour mark, considerably longer than the 12,000-15,000 hour marks experienced by most LM6000 units. Part of the reason for the extended interval may be the plant`s intermediate dispatch usage, which results in the turbines being run “softer.” The use of steam rather than water for NOx control also lessens gas turbine degradation because combustion chamber stresses are not inflicted via the phase change of water to steam during injection.

    The plant is staffed by 17 people. Eight operators, in four rotating two-person teams, control the plant, with one operator in the control room and one roaming the plant. Five maintenance persons perform daily maintenance, supplemented as necessary by GE personnel during planned outages. Three managers and an office assistant round out the staff.

    Sobered by the July demand spike, PSCo revised its year-2000 capacity requirement plans to the Colorado Public Utilities Commission (CPUC) from 169 MW in March 1998 to 676 MW in September 1998. Although PSCo will obtain some of the needed capacity through upgrades at its Fort St. Vrain and Valmont power plants, much will be needed from IPP plants such as Ft. Lupton. Ft. Lupton saw its capacity factor rise 10 to 15 percent in July compared with average levels throughout the year. The accompanying figure shows the generation profile at Ft. Lupton for the month of July 1998. Note the sustained elevated production levels in the second half of the month. A favorable component of PSCo`s plans before the CPUC is the seven-year contract provision, which will enable IPPs to attract financing to build new power plants and improve existing ones. Such provisions are important in ensuring the availability of power in Colorado as electricity demand continues to increase.