Maximizing a manufacturer’s combined heat and power plant

A Midwestern manufacturing facility opted for a hybrid combined-cycle steam turbine generator solution.
By Andrew Price, PE, and Aaron Wickersham, PE, Affiliated Engineers Inc. November 14, 2016

Learning objectives

  • Demonstrate the obstacles a manufacturing facility overcame as a combined heat and power (CHP) central plant mission changed.
  • Examine the efficiency benefits of a hybrid combined-cycle steam turbine generator.

Figure 6: This is an example of a project using COMcheck's space-by-space method showing compliance with the energy code. The space-by-space method may be more tedious to input data, as compared with the whole building method, but it may result in a proje Following a scale-down in manufacturing production, a Midwestern manufacturer’s combined heat and power (CHP) central plant mission changed. Identifying opportunities to optimize existing generating assets, the owner is increasing system efficiency with a hybrid combined-cycle steam turbine generator solution.

Totaling 2.5 million sq ft of conditioned space, the owner’s manufacturing and technical center complex has been served by a central plant that generates steam for heating and chilled water for cooling the complex. The central plant facility originally included:

  • A CHP system consisting of three nominal 15-MW combustion turbine (CT) prime movers and associated heat-recovery equipment
  • A nominal 5-MW backpressure steam turbine generator (STG)
  • A 3-MW backpressure STG.

The electrical power generated by the CHP system was indirectly used by the manufacturer’s campuses and other adjacent facilities. Steam was used at a pressure of 250 psig by industrial production facilities and space-heating needs, and at 15 psig by absorption chillers.

The real-time costs of electricity and gas are very dynamic and depend on many factors. Assuming a static cost of electricity of 6 cents/kWh and a fixed cost of natural gas of $6/decatherm (purchased utility heat rate of 10,000 Btu/kWh), the original operations of the central plant reduced fuel costs by approximately $3 million annually. CHP is the most cost-effective approach to generate electricity and has the least impact on regional air emissions. The CHP process is approximately 70% efficient as compared with utility-generated power at 35%.

As the owner reduced manufacturing production output at the complex, facility steam and chilled-water use declined and fewer central-plant-generated utilities were required. Because central-plant-generated chilled water was no longer needed by the complex, the absorption chillers were deactivated.

Although the dispatch of the CHP portion of the plant has changed significantly from the original intent, the central plant has been operated well and remains in good condition. Following the manufacturing scaledown, the central plant correctly operated in a temporary hybrid CHP mode of traditional CHP operation with the steam generated being used for heating purposes.

When there hasn’t been adequate heating demand and the electric costs were favorable as compared with natural gas costs (spark spread), the recovered steam has been condensed to cost-effectively generate additional electrical power with the existing steam turbine generators. The present operation of the plant within the limits of the existing equipment has been excellent with the proper staging and loading of the various generating components.

The ability to operate in this temporary hybrid mode has been reduced with the elimination of the absorption chiller usage and the 5-MW backpressure STG. These limitations led the owner to examine the replacement of the existing steam turbine generators.

Correcting capacity/load imbalance

Figure 2: This Midwestern manufacturer added a new nominal 12-MW condensing steam turbine generator with extraction capabilities and an exhaust pressure of 2.0 psia to provide lost capacity and more efficiently condense steam than with an existing steam tThe Affiliated Engineers Inc. team examined multiple options to replace the existing steam turbine generators. The study evaluated the current system’s operation efficiency and capacity, calculated future steam loads based on an independent campus planning effort, and compared multiple options to replace the existing steam turbine generators. Theoretical CHP dispatch models were developed and compared against present operating strategies.

The electric output of the plant is used in a commercial pricing node (CPN). The use of a CPN allows for cost-effective purchase of electricity for the complex as well as the owner’s adjacent installations. The purchase of electricity is based on the optimum mix of the following components:

  • Self-generation
  • Block purchases
  • Day-ahead pricing
  • Real-time pricing.


Superheated steam (600 psig/750°F) is produced in the heat-recovery steam generators (HRSG). This steam is passed through two existing backpressure steam turbine generators to produce additional electric power. STG No. 1 exhausts steam at a pressure of 15 psig with a peak electric generation of approximately 5.2 MW. STG No. 2 exhausts steam at a pressure of 250 psig for facility heating and was designed to generate approximately 3 MW of electric power. STG No. 2 is no longer in operation.

STG No. 1 exhaust was originally used in low-pressure steam-absorption chillers to supply cooling to the facility. The original plant configuration included an air-cooled condenser to condense a portion of the 15-psig steam. Due to the reduction in chilled-water demand, the absorption chillers are no longer in operation. A supplemental water-cooled condenser was installed when the absorption chillers were decommissioned. The condensing of 15-psig steam is not the most cost-effective manner to generate electric power. Most STGs used in a condensing mode operate in the range of 2 psia (vacuum).

Figure 1 indicates the steam- and electric-load duration curves for the central plant, given the reduced steam and chilled-water loads. The area above the steam-production curve to CT HRSG No. 3 capacity represents lost savings opportunity where equipment is sitting idle.

Because STG No. 1 operates at 15-psig exhaust and STG No. 2 is no longer operational, it was recommended that a new nominal 12-MW condensing STG with extraction capabilities be installed with an exhaust pressure of 2.0 psia. This new STG would provide the lost capacity of STG No. 2 and more efficiently condenses steam than STG No. 1. Figure 2 indicates the proposed range of operating configurations.

A new surface condenser is required to serve the proposed STG. The surface condenser would use the existing condenser-water system in a similar manner as the existing water-cooled condenser. The new STG and surface condenser would be installed within the existing plant.

The HRSG systems are provided with two flue gas economizers. The first stage unit is a traditional feedwater economizer that elevates boiler feedwater temperature to above 228°F. The second-stage downstream economizer elevates the water temperature between the hot well and deaerator. By using the proposed condensing STG, the entering water temperature of the second-stage economizer is reduced, allowing for increased heat recovery. The present average stack temperature is approximately 300 to 325°F. With the new STG, the stack temperature should be 275°F or lower, resulting in fewer stack losses and higher cycle efficiency.

Cost-reduction strategies

Figure 3: The cost of onsite electric generation is shown when condensing to maximize power output. A $0.01/kWh operation and maintenance (O&M) allowance is included in the fuel-cost differential.Figure 3 shows the cost of onsite electric generation when condensing to maximize power output. A 1 cent/kWh operation and maintenance allowance is included in the fuel-cost differential.

The proposed new water-cooled STG will reduce the cost of electric generation by 2 cents/kWh when the plant is operated in a combined-power cycle.

The initial cost of the proposed installation is approximately $5 million and will result in a simple amortization period of approximately 8 years.

In addition to the replacement STG, the study examined inlet cooling. The capacity and efficiency of a combustion turbine are inversely proportional to the entering air temperature of the unit. Precooling of combustion air to the turbine is a cost-effective method to increase generating capacity and efficiency during periods of elevated ambient conditions generally occurring during the summer. The precooling of the combustion turbines at the central plant would increase electric output by approximately 2,000 kW/unit and increase summer efficiency by approximately 8%.

The combustion turbine precooling system would consist of installing a cooling coil in each unit intake and using the plant-chilled water to indirectly cool the combustion air to approximately 60°F. It is strongly recommended that a separate glycol water system is installed to minimize operational impacts and prevent precooling coils from freezing.

The simple amortization period of the precooling depends on the value of the additional electric output that will be generated when grid electric prices are the highest. If a nominal value of $100/kW/year is applied, the simple amortization period is approximately 4 years.

Recommendations under implementation

The results of the study led the owner to move forward with a project to replace the existing backpressure steam turbine generators and condensers with a nominal 12-MW condensing steam turbine generator with extraction capabilities and a new surface condenser. It was determined that inlet cooling will be evaluated further after the installation and start-up of the new STG.

As the cost of electricity continues to increase with the decommissioning of coal-based utility stations and the conversion to gas, the economics of both the STG replacement and the combustion turbine inlet cooling will be enhanced. The generating efficiency of the CHP plant is significantly greater than utility generation. Self-generated and utility-generated power costs are presently determined by the prime mover fuel source. As utilities convert from coal to gas operations, self-generated electric power will become even more cost-effective.

Andrew Price is a market leader at Affiliated Engineers Inc. He specializes in the evaluation and design of efficient and reliable energy and utility infrastructure. Aaron Wickersham is a senior project manager at Affiliated Engineers Inc. Recent project experience includes CHP evaluations for the Architect of the Capitol, Pennsylvania State University, and the Centers for Disease Control and Prevention.