ASHRAE Technology Award... Texas Hospital Central Plant Redesign

A S H R A E J O U R N A L a s h r a e . o r g J A N U A R Y 2 0 1 43 6

A new 1.1 million ft2 (102 193 m2) research insti-tute 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 opera-tion 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.

BY BRUCE L. FLANIKEN, P.E., MEMBER ASHRAE

Texas HospitalCentral Plant Redesign

2013 ASHRAE TECHNOLOGY AWARD CASE STUDIES

SECOND PLACEHEALTH CARE FACILITIES, EXISTING

A new research institute at

Houston Methodist Hospital

prompted an expansion of the

central utility plant. New high

efficiency equipment included

a gas turbine-driven electrical

generator with duct burner and

high pressure heat recovery

steam generator with aqueous

ammonia selective catalytic

reduction.

ABOUT THE AUTHOR Bruce L. Flaniken, P.E., is design & construction manager of engineering at the Houston Methodist Hospital.

Central Utility PlantCogeneration CHP Upgrade

Location: Houston

Owner: Houston Methodist Hospital

Principal Use: Existing Hospital CUP

Includes: Two natural gas-fired, high pres-sure steam boilers; five electric drive water-cooled centrifugal chillers; two steam-driven, water-cooled centrifugal chillers including ancillary equipment (cooling towers, condenser/chiller water pumps) and electrical switchgear; gas turbine-driven electrical generator with duct burner and high-pressure heat recovery steam generator with aqueous ammonia selective catalytic reduction (SCR). The CUP now serves existing 1,000-bed hospital and 1.1 million ft2 research facility.

Employees/Occupants: 450

Gross Square Footage: 1.2 Million

Conditioned Space Square Footage: 1.1 Million

Substantial Completion/Occupancy: January 2011

Occupancy: 100%

BUILDING AT A GLANCE

This article was published in ASHRAE Journal, January 2014. Copyright 2014 ASHRAE. Posted at www.ashrae.org. This article may not be copied and/or distributed electronically or in paper form without permission of ASHRAE. For more information about ASHRAE Journal, visit www.ashrae.org.

J A N U A R Y 2 0 1 4 a s h r a e . o r g A S H R A E J O U R N A L 3 7

Therefore, they could not provide emergency cool-

ing, 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 hurri-

cane-type power grid outages. The system incremental

cost and estimated energy savings using simple pay-

back 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 com-

bined 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 60F [15.5C] DB/60% RH. Ambient inlet air becomes

de-rated to approximately 3.8 MW at 100F [38C]

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 over-

all 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 cool-

ing capability in cogeneration island mode (stand-alone

mode) when all power is lost to the facility.

Additional pump piping cross connections and man-

ual bypass/isolation valves also were installed to allow

dedicated chilled and condenser water pumps to cross

connect to other nearby chillers to the greatest extent

possible. Variable frequency drives (VFDs) were added to

all cooling tower fans and chilled water and condenser

water pumps to improve system response and wire-to-

water efficiency.

The installation of a 2,000 ton (7034 kW) steam turbine

chiller in 2004 was undertaken as part of an energy ini-

tiative rebate available from the local utility company.

Another separate chilled water distribution upgrade

project involved adding differential pressure sensors

to control secondary chilled water distribution pumps

driven by VFDs.

This was done primarily to improve system DT that was 2F to 3F (4C to 5C) lower than designed for in

the original chiller selections. It is an ongoing goal to

achieve a standardized DT of 12F (22C) throughout all buildings on site served by our district CHP. The CUP

now produces up to a total of 12,800 tons of chilled water

through five 2,000 ton (7034 kW) electric chillers, one

2,000 ton (7034 kW) steam-driven centrifugal chiller

and the new 2,800 ton (9847 kW) steam-driven centrifu-

gal chiller in an N+1 configuration throughout.

ABOVE Cogeneration system with new and existing cooling tower and power house.

LEFT Cogeneration system looking north.




The CUP can produce up to a total demand of

99,500 lb/h (12 537 g/s), 210 psig (1448 kPa) steam

through a 24,500 lb/h (3087 g/s) heat recovery steam

generator, a 25,000 lb/h (3150 g/s) natural gas-fired

duct burner and two high-pressure steam boilers

rated at 50,000 lb/h (6300 g/s) in a N+1 configuration

and with a boiler operated in standby low-fire mode

for quick steam demand response to CHP systems

shutdown, reducing energy consumption and emis-

sions of NOX.

A new 200 psig (1379 kPa) natural gas main from the

local utility company that included a high-pressure natu-

ral gas pressure regulating station was installed to serve

CHP and boiler loads while improving system perfor-

mance and reliability. A rooftop ammonia storage tank and

an at-grade fill station were installed to support the aque-

ous ammonia SCR emission controls system. A CHP con-

tinuous emissions monitoring system had to be installed

and operational at the time of start-up, which required

HMH to update all facilities overall air quality compliance

forms to meet state and federal emission requirements.

The BAS originally installed in the CUP was upgraded

to increase the degree of automation and optimization

that could be achieved to reduce staffing requirements

while improving systems reliability, record keeping and

maintenance. This will allow optimization of all CUP

chillers, pumps, cooling towers, CHP electrical genera-

tion, CHP thermal energy recovery (heat recovery steam

generator) and high-pressure steam boilers integration

in our efforts to maximize wire-to-water efficiencies.

Energy EfficiencyInstalling a new 2,800 ton (9847 kW) high efficiency

R-134a steam-driven centrifugal chiller to replace

the existing 2,000 ton (7034 kW) asynchronous elec-

tric motor-driven centrifugal R-22 chiller rated for

0.758 kW/ton reduced electrical demand by 1,600 kW.

Also, a modeled offset of nearly 1.5 million kWh of elec-

trical consumption was realized. The optimized opera-

tion of the primary chilled water supply loop and the

secondary chilled water loops systems has been greatly

enhanced by the building automation system, which

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research demands while reducing dependence on the

local power grid.

The hospitals steam demand profile requires pro-

ducing approximately 20,700 lb/h (2608 g/s) of steam

to meet heating, sterilizing, humidification, domestic

hot water steam loads, along with the steam demand

of a 2,800 ton (9847 kW) steam-driven centrifugal

chiller (requiring 25,300 lb/h [3188 g/s] of high-pres-

sure steam). This allows us to base load the CHP for

electrical power generation and recovered thermal

energy while rarely having to fire the high NOX steam

boilers.

Operation & MaintenanceExisting reliability, redundancy and other O&M issues

addressed during the project design and construction

phase included adding cooling tower capacity, along with

system piping and electrical system modifications that

provided a higher degree of overall functionality and reli-

ability. We have achieved cold weather operation of the

CUP using one 2,800 ton (9847 kW) steam-driven chiller

where previously it took a minimum of two 2,000 ton

(7034 kW) chillers.

This was achieved by improving AHU coil design DT to match the original design of 12F (22C) DT and adding UVC lights to keep cooling coils clean when replacing old

low DT air-handling units, by adding UVC lamps to exist-ing cleaned and refurbished AHU coils, and by better

secondary and primary chilled water systems differential

pressure and VFD control. The addition of the CHP and

associated protective switchgear has made the overall

system much more complex, but the added BAS automa-

tion and increased O&M training required by the system

have resulted in a more reliable and easier to troubleshoot

overall central utility plant, and one that certainly can

operate during extended power grid outages.

Cost EffectivenessThe natural gas-fired CHP cogeneration/heat recov-

ery steam generator/duct burner units were installed

to address both power capacity and emergency cool-

ing capability concerns. This gives HMH the ability to

allows improved wire-to-water

transfer of energy, reducing overall

energy consumption considerably.

InnovationThe use of a natural gas turbine-

driven CHP/heat recovery steam

generator/duct burner to provide

for the base steam demand, and that

required to run the steam-driven

chiller, has resulted in a substantial

shift in demand from the existing

utility power grid to the natural gas

utility and allowed us to produce up

to 2,800 tons (9847 kW) of chilled

water from free steam for only the

cost associated with running the

condenser-chilled water pumps and

cooling tower fans.

HMH can produce up to 6,800 tons

(23 915 kW) of emergency cooling

in the cogeneration (CHP) island

mode if all power is lost due to roll-

ing brownouts or storm damage.

This upgrades the ability to operate

a significant portion of the campus

while maintaining patient care and

Electricity MMBtu Gas MMBtu

2010 2011 Energy Mix 2011 2012 Energy Mix

FIGURE 1 Cogeneration decreased the dependency on electricity, reducing electric consumption and avoiding $1.85 mil-lion in net expense over 12 months. This cogeneration project is expected to return investment in fewer than two years.

12

10

8

6

4

2

0

Blend

ed $/

MMBt

u

Feb. Mar. Apr. May Jun. Jul. Aug. Sep. Oct. Nov. Dec. Jan.

FIGURE 2 Year-over-year change. Due to the reduction in electricity use (a higher expense energy source) the overall $MMBtu was reduced significantly and savings are higher than modeled.

2010 11 Blended $/MMBtu

2011 12 Blended $/MMBtu



(CHP) and used the free steam to run a steam-driven

chiller 8,456 hours during this period, making maximum

use of the free thermal energy recovered by the heat

recovery steam generator. While we found it difficult to

compute the exact savings derived from cogeneration due

to dramatic utility cost fluctuations that occurred during

the project, we were able to calculate energy cost savings

of approximately $1.85 million mainly due to the added

thermal energy recovery (Figure 1).

We averaged electrical and natural gas use and cost

via a blended $/MMBtu (Figure 2). This translates to a

total annual gross savings of $2.2 million from Feb. 2011

FIGURE 3 Shift of energy expense due to cogeneration (from 20112012). While installation of the cogeneration operation increased maintenance and standby gas expense, the benefit of avoided util-ity expense of more than $1.3 million and more than $800,000 of free steam generation established this project as a best practice standard for reducing expense and lowering carbon footprint.

$2 Million

$1.5 Million

$1 Million

$500,000

$0

$(500,000)Feb. Mar. Apr. May Jun. Jul Aug. Sep. Oct. Nov. Dec. Jan.

self-generate electrical power and achieve sav-

ings in energy costs while in the cogeneration

mode. The $1 million annual estimated energy

savings resulting from the overall increased

thermal efficiency of the CHP (from 30% to

approximately 88%) came from base load-

ing of the CHP unit for both power and steam

consumption (24/7/365). This completely off-

set the added cost of the upgrade from a new

high-pressure steam boiler and a new 2.5 MW

emergency diesel generator to the 4.3 MW gas-

fired cogeneration turbine/heat recovery steam

generator/duct burner unit with a modeled

payback between three and four years.

The project achieved a 92.2%+ annual operating

hours (8,079 hours of operation) for cogeneration

Actual Net Savings: $1.85 Million Avoided UtilityFree Stream Increased Standby GasIncreased Maintenance


J A N U A R Y 2 0 1 4 a s h r a e . o r g A S H R A E J O U R N A L 4 3


through Jan. 2012 with a net annual avoided cost of $1 mil-

lion. One additional cost that had to be included was the

cost of running one of the high-pressure steam boilers at

low fire during cogeneration (CHP) mode so that in the

event of cogeneration shutdown we could get the high-

pressure steam system operational in under an hour.

That additional annual operation cost was $73,726.

Also, we have added the calculated cost of chilled water

demand load and power consumption savings on the

CUP chilled water production by recovering 24,500 lb/h

(3087 g/s) of high-pressure steam from the cogenera-

tion heat recovery steam generator for an annual total

of 294,000 lb/h (37043 g/s) of high-pressure steam

(165,541.6 MMBtu). That steam is used to produce 21

million ton hours of cooling via the steam-driven cen-

trifugal chillers at an estimated savings of $817,523 for a

combined annual net savings of $1.8 million from Feb.

2011 through Jan. 2012. This puts the simple payback at

2.16 years versus four years as initially modeled.

Systems overall heat transfer efficiency for the cogen-

eration (CHP) unit increased from around 30% for gen-

eration of electric power to slightly above 88% by using

the heat recovery steam generator unit to capture

the free waste heat and use it effectively to generate

domestic hot water, heating hot water, sterilizer steam

and/or chilled water in the manifolded high-pressure

steam distribution system.

The environmental impact from NOX emissions has

been reduced by selecting a gas turbine-generator CHP

unit using aqueous ammonia SCR with best available

control technology rated to produce maximum 15 ppm

NOX in lieu of high-pressure steam boilers. Using the

EPA CHP emissions calculator, the CHP system will

reduce NOX by a net reduction of 71% or 20.79 tons/year

(56.9 kg/year), SO2 by a net reduction of 100% or

56.10 tons/year (154 kg/year) and will reduce CO2 by

10,511 tons/year (28,797 kg/year) or 28%.

Expensive hurdles included site adaptation of the exist-

ing 50-year-old CUP roof structural support to install

the equipment on the roof and getting a crane to set up

the equipment without closing the hospital main patient

drop-off. Others were limited working space access adja-

cent to the emergency entrance/ambulance drive and the

ongoing construction of the new research building.




Integrating the xisting plant BAS and CHP system con-

trols, installing the chiller, cooling tower and piping cross

connections without shutting down the existing CUP

utilities had to be carefully planned and mitigated.

The heat recovery steam generator can recover

24,500 lb/h (3087 g/s) of free high-pressure 210 psig

(1448 kPa) steam from the turbine engine discharge gases.

The duct burner was selected to generate an additional

25,000 lb/h (3150 g/s) of high-pressure 210 psig (1448 kPa)

steam by injecting fuel to the closed gas turbine discharge

where there was sufficient oxygen to get an extremely

efficient burn with minimal heat loss. This allowed us to

base load the heat recovery steam generator and recover

high-pressure steam while running only one high-pres-

sure steam boiler November through February.

The recovery and use of this lower cost steam is what

improved payback and pushed overall thermal effi-

ciency to 88.1% while keeping loss of thermal efficiency

to the flue stack to 11.9% of input gas ratings. HMH also

base loaded the CHP electrical generation capacity so it

would not have to negotiate interconnectivity fees with

the local utility. HMH received a local utility rebate of

approximately $450,000 for the kW demand displaced

by the steam centrifugal chiller.

A lesson learned was that we should have included the

turbine inlet chilled water cooling coil to reduce entering

air temperature to 57F (14C) ISO year-round to allow the

turbine to operate at maximum efficiency due to denser,

cooler air intake and produce the full 4.5 MW of power at

all outside air temperatures. The cost to add that now as

a separate project is about $1.2 million, while including

it initially would have cost about $750,000, reducing the

simple payback from nearly five years to about three years

or less. In Houston, there are approximately 7,080 hours

where the outside air temperature is above the 57F (14C)

ISO temperature that allows the CHP turbine to produce

4.5 MW of power, in lieu of the de-rating to approximately

3.8 MW at 100F (38C) DB/60% RH of standby power at

4,160 V via a natural gas-turbine generator.

Another lesson learned is that we should have set up

the electrical systems protection relays to shut down the

cogeneration unit, rather than the main power feed from

the utility company as this is less disruptive of our side and

still protects the utility and hospital systems as required.


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ASHRAE Technology Award... Texas Hospital Central Plant Redesign