The centralized plants of big energy users, such as hospitals and universities, can be ideal candidates for cogeneration or combined heat and power (CHP) installations. However, evaluating costs and benefits can make return-on-investment calculations difficult, especially with new facilities that lack historical operating data.
The centralized plants of big energy users, such as hospitals and universities, can be ideal candidates for cogeneration or combined heat and power (CHP) installations. However, evaluating costs and benefits can make return-on-investment calculations difficult, especially with new facilities that lack historical operating data. The good news is that engineers don't have to operate in the dark, so to speak, as reliable, thoroughly beta-tested software is available and can be a valuable resource for evaluating alternative M/E/P approaches during a project's preliminary design phase.
In fact, with an initial understanding of a building's dimensions and envelope construction materials, along with various occupancy requirements, times of use and properly formatted local microclimatic annual weather data, engineers can simulate energy use and costs for a wide range of strategies.
Of course, the feasibility of any CHP approach depends on the magnitude, duration and coincidence of electrical and thermal loads, and on the selection of the prime mover and waste-heat recovery systems. There's also no getting around the fact that the integration of electrical and thermal requirements with a cogeneration plant will be a major challenge.
Other key components of a CHP plant should include an examination of generator(s), the control system and connections to building mechanical and electrical services.
Optimum performance depends on how these various components are specified and integrated, and the range of variables means that there is no single path to follow. Instead, engineers have to understand how their specific design will function throughout a full year's operation, comparing alternative solutions and their respective cost implications.
Following is a real-world case study of a CHP evaluation undertaken for a Midwestern medical center. The example shows how new software products can help engineers analyze options to give owners the information they need to make informed decisions. In this case, the facility is a nominal 1.1-million-sq.-ft. medical operation that includes a pair of 12-story medical office towers and an adjacent six-story hospital.
The goal of the study was to determine the comparative economic benefits of three separate central plants vs. a single CHP generating all on-site cooling, heating and power needs. Employed for the analysis was a software package called Energy System Analysis Series (ESAS) that helped system designers compare possible solutions throughout a range of operating conditions.
This product incorporates several separate modules to model energy performance and system characteristics of commercial, industrial and institutional buildings under a variety of design, operating and ambient weather conditions. Although the software outputs hourly data for an entire year of operation, the entire library of programs can be installed and run on any computer with a 20-MB or greater hard drive and a math co-processor.
The hospital being studied has its own laundry, which, when combined with its food service area, creates a sizable water-heating load. Hourly profiles for lighting, receptacle, occupancy, thermostat, fan operation and service water heating vary extensively (see adjacenttable). All areas except administrative offices have continuous (8,760 hours) fan operation and are heated and cooled by variable-air-volume (VAV) distribution systems with reheat boxes activated at the required minimum primary-air damper setting. Nine separate VAV zones serve the building.
The ventilating air requirement is modeled as a constant percentage, ranging from 20% to 80% of the supply airflow, depending on occupancy needs. All VAV systems have both outdoor air economizer and fan inlet vane damper controls.
Each of the two identical towers is heated and cooled by VAV distribution systems. Separate VAV systems—one per exposure—serve each of the perimeter zones, and one VAV system serves the interior zone for all floors. Primary air supply temperature is set at 55
Simulating a CHP plant
The proposed CHP plant simulated in this study included a gas-turbine, an engine-driven centrifugal chiller, a packaged gas-turbine cogeneration unit (PGTCU) with a heat-recovery steam-generator unit (STGU), a deaerator, a thermal energy-storage (TES) system—cold and hot—and cooling towers. A control room built in the plant would incorporate the turbine control system panel, a boiler and auxiliary equipment control and a monitoring system. The plant also would have two 180-boiler-horsepower (BHP) gas-fired hot-water boilers and one nominal 31-BHP hot-water converter, with one hot-water storage tank for space heating service and one nominal 80-BHP hot-water heater for domestic hot-water service. The plant would be located above the ground and adjacent to the hospital/office complex and provide the required heating, steam, chilled water for cooling and a peak electrical power of 3,787 kW for the entire complex.
The gas-turbine/centrifugal chiller (GT/CC) was projected as a nominal 2,000-ton centrifugal unit, driven by a gas turbine capable of delivering 1,568 brake horsepower at an inlet-air temperature of 59While this would take some cooling tonnage, there would be a net reduction in energy cost. The available exhaust-heat energy would be ducted to the HRSG to generate steam, which would then drive a condensing steam turbine with a power output of 2,325 kW.
The PGTCU was specified to include a gas turbine, a separate generator, a turbine exhaust system, an HRSG and a control system. The nominal 1.5-MW cogeneration unit would dissipate its waste heat together with the available exhaust-heat energy from the GT/CC transferred into the HRSG.
The STGU was specified as a multistage condensing model, consisting of both a steam turbine and a condensing unit. The superheated steam rate exiting the HRSG and piped to the STGU would generate 2,325 kW of additional electricity. Its condensing unit would be equipped with two condensate pumps and two 3,000-gpm cooling-water pumps supplying cooling water at 85
The PGTCU was designed to commence operation when the load fell below 1,462 kW. Steam generated from its HRSG would supply the hot-water converter to produce hot water, which would then go into the hot-water storage tank to produce up to 17,586 kW for space heating. If the storage tank became full, steam would be dissipated. The STGU was designed to go online automatically when electrical load exceeded 1,462 kW, driven by the unfired heat-recovery from the PGTCU. If this heat was insufficient to produce the steam required by the additional load, the PGTCU duct burner would fire to produce the required 812 MBTU at the STGU.
In the summertime, the STGU would recover heat from both the GT/CC and the PGTCU to produce the full power output. In the wintertime, when the GT/CC was not operating, the STGU only would produce 50% of its rated output; therefore, a portion of the 3,300-kW load would need to be purchased from the local utility.
The simulation was based on the initial schematics, preliminary plans and other programmatic information developed by the client's original A/E team. Due to the size of the project and adjacencies of buildings within the complex, we decided to conduct a comparative simulation using state-of-the-art computer programs to decide whether to construct separate, conventionally designed HVAC plants within each of the three buildings.
When designing a TES plant, one must consider three major points: plant operation; operating costs vs. installation costs; and system sizing. Additionally, three operational modes generally must be weighed: serve the base-cooling load with one chiller and use the TES to satisfy peak loads; serve the base cooling with the TES and use the chiller to satisfy the peak; or require the TES to satisfy 100% of the peak load, recharging the TES tank during off-peak hours. Since the hospital has a fairly high continuous cooling load, a full TES system is not warranted.
The comparative analysis showed substantial annual operating savings favoring the proposed CHP plant, resulting from an overall reduction in utility and maintenance costs. Operating cost savings are mainly due to the fact that approximately 95% of the total required annual electrical power is produced on site by cogeneration. Therefore, only 5% of its annual estimated power needs are purchased from a utility.
Additionally, reducing the number of plant operators helped cut proposed operating costs. Although the installed first cost of the proposed plant was higher in comparison, the estimated total operating cost savings of approximately $1,244,500 per year resulted in a cost-effective, simple payback period of 1.8 years for the proposed CHP plant. Additionally, the design of the proposed CHP plant has resulted in a substantially compact central plant—an approximately 29% decrease in physical size—in comparison to the base plant having three separate central plants. The fully dedicated, proposed CHP plant, as demonstrated by the results of building simulation reported earlier, contributed to reduced demand charges associated with the time-of-use electrical rates, better operation and maintenance, efficient energy management, higher overall system efficiency and reduced levels of emissions and noise.
To estimate maintenance and repair costs for both the base and proposed plants, equipment manufacturers were consulted. These costs included major chiller cogeneration equipment and boiler overhaul over the life span of the equipment. Accordingly, the average maintenance and repair costs for the chillers are assumed to be $43.80/ton/year and $4.38/MBTU/year, respectively. The maintenance and repair costs for the gas and steam turbines for the proposed plant are estimated to be $262,800/year. The plant operator cost is estimated based on one person, 24 hr./day, 365 days/year at $35/hr., fully loaded, per plant. The lower portion of adjacent table presents the operating cost savings and installed cost premium for the proposed plant. The ratio of these two quantities gives the simple payback period as 1.8 years.
An educational tool
Demand for energy in the 21st century, particularly in less developed countries, could rise precipitously. Onsite CHP plants, incorporating state-of-the-art energy conservation, heat recovery and waste-minimization features, offer one approach for minimizing wasted energy. However, overall cost effectiveness of these installations depends on a true understanding of how the system will perform over time. Today's computer-modeling capabilities provide engineers with a valuable tool for predicting performance and perfecting designs.
Table: A Real-World Case Study
Gross floor area
Conditioned floor area
Vision glass area
31% of gross exterior wall
31% of gross exterior wall
Glass shading coefficient
Glass overall U-value
Opaque wall U-value
15 W/m2%%MDASSML%% 27 W/m2, based on functional needs
"21.5 W/m2(task areas) 10.8 W/m2(non-task areas) 2.2 W/m2(unconditioned areas)"
5.4 W/m2%%MDASSML%% 10.8
10.8 W/m2(conditioned areas)
9.3 m2person - 37.2 m2/person
How it worked
A number of modules within the Energy System Analysis Series (ESAS) software package were used to get a full picture of how much each proposed scheme would cost to operate. The first table summarizes installed first costs. The second table summarizes ongoing operating costs.
The ESAS package was able to simulate electricity and gas consumption costs. The package's Building & Distribution System Program (ERE) module calculated the thermal and electrical loads hourly for each of the representative buildings, and simulated the operation of the air-distribution system in satisfying these loads for a full year.
The Building Section Summation & Cooling Storage Program (TCR) module summed up the hourly, full-year loads from the multiple ERE computer runs of various building sections to find total diversified system loads to be satisfied by a given mechanical plant configuration.
Finally, the Mechanical Plant Analysis Program (EEC) module simulated the operation of the various pieces of plant equipment on an hourly, full-year basis as they responded to loads imposed by the building's air-side system.
Comparative Installed First Costs
Base Plant Cost For Individual Buildings ($)
TOTAL BASE PLANT COST($)
TOTAL PROPOSED PLANT COST ($)
GAS TURBINE/CHILLER UNIT
STEAM TURBINE/CONDENSING UNIT
HHW STORAGE TANK
CONTROL ROOM A/C
OVERHEAD & PROFIT
Comparative Economic Analysis
ANNUAL ENERGY COST
ANNUAL COOLING TOWER WATER COSTS
ANNUAL MAINTENANCE COST
GAS & STEAM TURBINES
TOTAL OPERATING COST
SAVINGS VS. BASE PLANT
INSTALLED FIRST COST (refer to table above)
COST PREMIUM VS. BASE PLANT