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Texas Hospital Central Plant Redesign

©2014 This excerpt taken from the article of the same name which appeared in ASHRAE Journal, vol. 56, no. 1, January 2014.

By Bruce L. Flaniken, P.E., Member ASHRAE

About the Authors
Bruce L. Flaniken, P.E., is design & construction manager of engineering at the Houston Methodist Hospital.

A new 1.1 million ft2 (102 193 m2) research institute building at Houston Methodist Hospital (HMH) prompted an expansion of its existing central utility plant (CUP). The steam demand on the CUP required operation of the two existing natural gas 60,000 lb/h (7560 g/s) high-pressure steam boilers, leaving the plant without a standby unit. Although the CUP had sufficient chiller capacity, it was deficient in the necessary cooling tower capacity to support operation of all seven of the installed centrifugal chillers simultaneously.

Auxiliary equipment for the one existing steam-driven chiller and/or ancillary equipment of any of the electric drive chillers (cooling towers, condenser/chiller water pumps) were not connected to standby power.

Therefore, they could not provide emergency cooling, which was required by the new research building as well as being necessary to care for patients during major storms and hurricanes that cause utility outages in Texas.

The installation of the cogeneration turbine with duct burner and high-pressure steam thermal energy recovery unit makes HMH the only hospital in the Texas Gulf Coast area that can operate during hurricane-type power grid outages. The system incremental cost and estimated energy savings using simple payback had been projected to pay back in 3.5 years or less.

The CUP upgrade project directly addressed the cooling tower deficiency by installing an additional 6,800 tons (23,915 kW) of cooling tower capacity in the form of seven additional cells. The standby steam and power concerns were addressed by the installation of a 200 psig (1379 kPa) natural gas turbine-generator combined heat and power (CHP) unit to increase overall thermal efficiency and produce steam via a combination heat recovery steam generator and natural gas-fired duct burner of standby power at 4,160 V via a natural gas-turbine generator. (Note: the actual capacity of the 4.3 MW cogeneration unit varies depending upon outside air temperature and percent relative humidity. Initial capacity rating is given at ISO inlet air conditions of 60°F [15.5°C] DB/60% RH. Ambient inlet air becomes de-rated to approximately 3.8 MW at 100°F [38°C] DB/60% RH.)

The CHP unit was installed to address standby power and emergency cooling capability concerns. This unit allows HMH to generate its own electrical power and take advantage of reduced energy mix cost, and increase CHP thermal efficiency while in the CHP mode.

The installation of the higher cost low NOX output CHP turbine with aqueous ammonia selective catalytic reduction (SCR) significantly decreased NOX emissions. It also reduced the overall permit application time in an EPA non-attainment zone (by submitting it to EPA using best available control technologies, which reduced overall NOX output substantially).

Existing chilled water emergency cooling concerns were addressed through the addition of a 2,800 ton (9847 kW) steam turbine-driven chiller and by revising the existing electrical power distribution, feeding standby power to other electric chillers and their auxiliary equipment. This provides for 6,800 tons (23 915 kW) of emergency cooling capability in cogeneration island mode (stand-alone mode) when all power is lost to the facility.

 

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