Campus district energy system steady improvements in system efficiency

The utility and energy management oper-ation at the University of Texas at Austin main campus has returned to 1977 natural gas consumption levels even with and additional 8 million square feet (743,000 m2) on campus by improving the efficiency of the on-site utility system. This was accomplished using proven off-the-shelf technology, capital improvements and innovation in a manner that has increased plant capacity to meet the next 30 years of projected campus growth. The utility system has been self generating 100% of all energy since 1929 with extremely high reliability, adding value to the campus, increasing efficiency and translating into self funded improvements and significant emissions reductions.

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Aerial view of the energy plant

The university is a dense urban campus of over 17 million square feet in 200 buildings serving 70,000 students, faculty, and staff. Eighty percent of the 17 million square feet (1,6 million m2) on campus is research oriented and operates 24 hours a day year round requiring a variable and uninterrupted supply of energy.

The buildings are connected through a district energy system with all utilities centrally generated. Connections to the surrounding city electrical grid exist only for emergency backup, providing the University independence and versatility in generating the electricity, chilled water, heating steam and other utilities required on campus, resulting in reliability of 99.9998% over the last 35 years for all delivered energy.

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This system is a perfect example of how combined heat and power (CHP) and district energy (DE) can be used to reduce carbon emissions and an example how this can be implemented right in the middle of a campus located in the center of a city. An aerial view of the heating and power plant indicates the proximity of the plant to campus facilities. To the south of the campus one can find the State Capitol Complex and to the North and East and West are residential neighborhoods that have co-existed for about 81 years.

The CHP system was originally started in 1929 using a lignite fired boiler steam system that was used to generate 3 MW of electricity using two 1.5 MW steam turbines, plus heat for the campus. The system was converted to use natural gas in the 1930s and has evolved to a system that produces 350 GWh of electricity, 980 million lbs (440 million kg) of steam and 136 million ton/hrs of chilled water annually through six miles (9.6 km) of underground distribution tunnels and over 30 miles (48 km) of underground electrical distribution duct banks.


The installed equipment includes 137 MW of on-site CHP, 1.2 million lbs/hr of steam generation and 48,000 tons (43,500 tonnes) of chilled water capacity. A four million gallon chilled water thermal energy storage system is scheduled to come on line by September 2010.

Tables 1 and 2 present an inventory of equipment used at the site.

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The system is operated in a combined cycle mode comprised of a combustion turbine with heat recovery steam generator (HRSG) paired with a steam turbine. Maximum electrical generation efficiency is obtained by operating the combustion turbine as high as possible, using the inlet air cooler in hot weather, and matching the HRSG steam output to the steam turbine generator to match the exact campus electrical load requirement.

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Steam is extracted from the turbine to supply steam to the campus for heating and hot water generation in the facilities. The boilers are operated to provide peak steam needs above and beyond what can be produced by the HRSGs and they provide a backup steam source in the event of a combustion turbine/HRSG upset.

The system is able to operate at extremely high efficiencies because the 1967 and 1959 boilers have been retrofitted with combustion controls that allow the boilers to operate at about 85% plus efficiencies using variable frequency drives to control flue gas recirculation and combustion air. This reduces NOx and allows the backup boilers to be banked as needed at only 1 MMBTU/hr to maintain a ‘spinning steam reserve’ yet be responsive to a sudden full load need in about two minutes.


Concrete tunnel systems distribute chilled water, steam, compressed air and recovered water to and from the buildings and plants. The tunnel system is a major advantage to the reliable operation of the campus because it allows for easy repairs as needed, replacement of valves and controls without impacting the operation of buildings allowing for required outages to be kept to a minimum.

Reliability has been a key component of the operation and master planning of the utility system from the inception. To this end each building is equipped with two electrical substations, two chilled water connections, two steam connections and two domestic water connections.

The campus electrical distribution system is configured as a looped system with 100% redundant high voltage switchgear on 12 switchgear systems and is connected to a 69 KV to 12,000 KV substation with four 50 MVA transformers connected via a ring bus. This entire system is managed using a digital SCADA system.

The substation ring bus provides up to a maximum 100 MVA load, though the campus exceeds 50 MVA only about 20% of the year. The substation was upgraded in 2004 to accommodate 30 years of projected campus growth and the entire power plant electrical distribution system was replaced and upgraded at the same time. In essence ‘N+4’ reliability exists at the substation 80% of the time and there is 100% backup for the power plant switchgear.


All utilities on campus are ultimately generated from natural gas, so while relatively clean-burning, carbon emissions are still a large concern. However, due to the high efficiency and versatility provided by the campus’s district energy system, and advances in the efficiency and operations in utilities generation, carbon emissions have been held at steady levels in spite of the constantly increasing campus demands. Figure 1 on page 40 illustrates the past 32 years of plant operations, demonstrating the years of campus growth with no efficiency initiatives, followed by a combination of demand side projects and ongoing utility improvements that have reduced carbon levels back to 1977 levels.

Compared to 1977, the campus is now nearly twice the size incrising from 9 million to 17 million square feet (836,000 m2 to 1,579,000 m2)) with over double the electrical demand (183,000 MWh to 372,000 MWh annual) yet emissions remain the same and are anticipated to decrease as new technology such as combustion turbine 10 and the thermal energy storage tank come online.

The alternative to generating electricity, steam, and chilled water on campus would be purchasing electricity and natural gas to meet campus needs. Purchasing grid electricity for building loads and chilling stations, and burning natural gas for space heating and hot water, would eliminate many of the advantages of the district energy system.

Even with Texas boasting the largest amount of wind energy in the country and several nuclear plants, the mix of coal and natural gas used to generate electricity does not compare to the efficiency of the CHP facilities on the university campus. The disparity between self-generated energy on campus and purchased grid energy will continue to widen, as efficiency improvement projects are continuously implemented on campus.

The next few sections will cover a number of the emissions and efficiency projects already completed. The basic objective 12 years ago was to convert the operation of the plant to a ‘true’ combined-cycle operation as much as possible. This was a challenge since digital controls did not exist, firm capacity was eroded due to campus growth, most of the electrical distribution system was beyond useful life and the plant was operated blindly using historical experience rather than based on actual operational needs.


Prior to 2001 only combustion turbine (CT) 8 was registered with an air permit according to EPA regulations. The compliance strategy was this:

  • Boiler 3 (1959, 150,000 lbs/hr) and Boiler 7 (1968, 500,000 lbs/hr) fired with natural gas would be retrofitted with emissions reduction equipment that would reduce NOx from 0.21 lbs/mmbtu to 0.03 lbs/mmbtu. They would also not be operated more than 720 hours at 0.06 lbs/mmbtu of NOx on back-up fuel oil.
  • CT 6 (1967, 13 MW & 90,000 lb/hr HRSG) operating hours would be reduced to operate no more than 1500 hours per year using natural gas. The CT was too old and inefficient to justify making a significant expense to reduce emissions. (This turbine has since been demolished to accommodate a new General Electric LM-2500+ G4 CT with HRSG in its place).
  • Boilers 1 & 2 (1948, 75,000 lbs/hr) operating hours would be reduced to operate no more than 2500 hrs/yr using natural gas. The boilers were too old and inefficient to justify making a significant expense to reduce emissions.

Rather than replace the burners on Boilers 3 & 7 with expensive low NOx burners, compounded by the issue that the low NOx burner suppliers would not guarantee the target of 0.03 lbs/mmbtu, an innovative NOx reduction approach was implemented that was half the price, plus proposed an energy savings payback. The approach proposed by Benz Air Engineering used flue gas recirculation, variable frequency drives (VFDs) to regulate flue gas and combustion air, removed boiler dampers and used software to monitor and control excess O2, NOx and regulate natural gas flow.

This strategy was very successful in achieving the emissions reductions for both natural gas and fuel oil and energy savings paid for the retrofits in two years. Fan horsepower was significantly reduced and unlimited turndown on the boilers is now possible. This is important because the boilers are used only to handle swing steam needs above the free steam amount produced by the HRSGs.

Since beginning the project in 2004, total plant nitrous oxide levels have seen a 30% annual reduction, carbon monoxide emissions have seen a 47% reduction, and sulfur dioxide emissions, even being initially low, dropped 38%. These are emissions reductions in the face of increasing campus energy demands, and will continue to decrease with the commissioning of combustion turbine 10 equipped with a urea selective catalytic reduction (SCR) system.


The university is tied to using natural gas as a fuel and using the CHP system, so achieving reductions in carbon dioxide and other emissions had to come from increased plant efficiencies. The focus has been on using innovative technological solutions as a strategy for the future. The other approaches used are:

  • A passive steam dump system was installed to vent excess steam if a steam turbine tripped eliminating the need to have hot standby steam turbines. The dump system is totally passive and does not use any energy when not needed. If an upset were to occur the excess steam is vented to the atmosphere only for the period of the upset, without excess noise, which provides around 200,000 mmbtu of annually recurring gas savings.
  • The primary cooling tower for the power plant originally installed in 1958 was replaced with a new fiberglass cooling tower with variable frequency drives that match cooling water needs to the demand. This project saves the campus about 50,000 mmbtus per year of fuel.
  • A new more efficient 25 MW steam turbine generator was installed in 2004 which provides around 200,000 mmbtu of annual fuel savings so the 1978 steam turbine is now a back-up unit.
  • à‚ A new 15,000 ton (13,600 tonne) chilling station was just commissioned to replace a 50 year old steam turbine driven chiller plant. This new plant operates with 100% variable frequency drives on three 5000 ton (4500 tonne) York Titan chillers and all associated pumps and cooling tower equipment is the first of its kind. This is the first 100% VFD plant of this size commissioned by York/Johnson Controls. This plant is performing at ultra high efficiencies due to the use of Optimum Energy’s chilling plant optimizer.
  • Inlet air coils for the two combustion turbines are projected to save around 120,000 mmbtus per year.
  • New 34 MW combustion turbine with HRSG and a 4 million gallon thermal energy storage system are projected to save a combined 400,000 mmbtus annually.
  • Modeling technology to operate, optimize and sustain efficiencies. This is a list of the technologies employed.
    • à‚ PE Advisor, developed by LightRidge Resources, is a real time model of the entire plant system that is used to validate existing performance, evaluate operating scenarios that can improve efficiency and evaluate the optimum sizing and replacement of equipment replacement.
    • à‚ Termis, developed by 7T, is a real time hydraulic model of the chilled water distribution system that is used to operate and optimize pumping horsepower and optimum chilling plant dispatch needed to send the peak 50,000 GPM of chilled water through the 12 miles (19 km) of piping in campus tunnels.

The University of Texas at Austin has had a long tradition of reliability, cost effectiveness and reliability in the utility operation. This has allowed the campus to increase total efficiency from 62% 12 years ago to a projected 90% next year. This has included improving the average annual heat rate from 12,600 Btu/kW to 9800 Btu/kW which will be further improved with the new GE CT. This has resulted in $150 million in plant improvements being funded without a net increase in budget because fuel savings offset the debt.

This tradition has been taken to a new level by a continuous self sustained culture of continuous improvement using technology to continue to meet the mission of the campus in educating future generations of students that will help shape the future of the world.

Juan M. Ontiveros, PE, is the executive director of Utilities and Energy Management at the University of Texas at Austin.


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