The United States Environmental Protection Agency (USEPA)’s announcement that it will revise the effluent limitation guidelines for steam electric power generating units could affect not only how power plants use water, but also how they discharge it. The revised guidelines may lower discharge limits for various contaminants in flue gas desulfurization (FGD) wastewater including mercury, selenium, arsenic, and nitrate/nitrite. Although the specific details of the guidelines are unknown at present, the power industry is evaluating various technologies that may address the new effluent limitation guidelines and promote water conservation. Moreover, the power industry is looking for avenues to increase water usage efficiency, reuse and recycle throughout its plant processes. Final rule approval is expected by the middle of 2014 and new regulations are expected to be implemented between 2017 and 2022 through 5-year NPDES permit cycles. discharge limits for various contaminants including arsenic, mercury, selenium, and nitrate/nitrite [1]. These pollutant limits may be below the levels achievable today with conventional treatment [2]. A growing interest exists in zero liquid discharge (ZLD) facilities and processes in power plant operations. Potentially stringent discharge limits along with water conservation and reuse efforts are two of the major drivers to achieve ZLD. Potential pollutant levels are so low that ZLD may be the best option, if not an outright requirement [1]. Thermal ZLD systems have been the subject of increased interest and discussion lately. They employ evaporating processes such as ponds, evaporators and crystallizers, or spray dryers to produce a reusable water stream and a solid residue (i.e. waste). Evaporators and crystallizers have been employed in the power industry for a number of years. However, typical A growing interest exists in zero liquid discharge (ZLD) facilities and processes in power plant operations. Potentially stringent discharge limits along with water conservation and reuse efforts are two of the major drivers to achieve ZLD. Potential pollutant levels are so low that ZLD may be the best option, if not an outright requirement. A key disadvantage of thermal ZLD is its high capital cost. One way to reduce this cost is to pre-treat the liquid stream using innovative membrane technologies and reverse osmosis (RO).

Combined cycle power plants fueled with natural gas have been increasingly preferred by regulatory agencies for new power generation projects, compared with traditional coal-fired plants. With growing concerns about water resource availability and the environmental impact of wet cooling systems, there has been an increasing trend for new combined cycle projects to incorporate dry cooling, often as a mandate for regulatory approval of the project. There appears to be little consideration given to the impact of less efficient dry cooling systems on unit efficiency, and particularly on increased fuel requirements and therefore carbon dioxide (CO 2 ) emissions for a given power generating output. The trade-off between reduction of water use and increased fuel requirements with dry cooling should be included as part of the decision on the selection of cooling systems for new fossil plant construction.

The reduction of water consumption and use is emerging as a top priority for all types of thermoelectric power plants. In the United States, thermoelectric power production accounts for approximately 41% of freshwater withdrawals [1] and 3% of overall fresh water consumption. [2] On the basis of responses to a 2011 Electric Power Research Institute (EPRI) Request for Information [3], the feasibility study [4,5,6,7] of a Thermosyphon Cooler Hybrid System (TCHS) [8], proposed by Johnson Controls, was funded under EPRI’s Technology Innovation (TI) Water-Conservation Program. The objective of this project was to further develop the TCHS design concept for larger scale power plant applications and then perform a thorough technical and economic feasibility evaluation of the TSC Hybrid System and compare it to a variety of other competitive heat rejection systems. The Thermosyphon Cooler Hybrid System reduces power plant cooling tower evaporative water loss by pre-cooling the condenser loop water through a dry cooling process employing an energy efficient, naturally recirculating refrigerant loop. This paper details the results of a detailed feasibility study that was conducted to compare the cost and performance of the TCHS to a number of other potential wet, dry, and hybrid thermoelectric power plant heat rejection systems operating under varying degrees of water constraint. Installed system cost estimates were developed for the base all wet cooling tower systems, TCHS’s of varying sizes, air-cooled condenser (ACC) hybrid systems of varying sizes, and all dry ACC systems. Optimized all wet cooling tower and all dry ACC system configurations were developed for five different climatic locations. A comprehensive power plant simulation program that evaluated the fuel and water requirements of the power plants equipped with the different heat rejection systems across the weather conditions associated with all 8,760 hours of a typical meteorological year was developed and then an extensive array of simulations were run each location. The summary data were organized in a separate interactive dynamic system comparison summary program to allow users to gain further insight into the relationships between the various heat rejection systems and the sensitivity of the results to changes in key input assumptions. This paper details the data presented in the interactive dynamic system comparison summary program. This program displays the key metrics of the Annual Net Cost of Power Production, the Annual Net Power Plant Profit, the Annual Operating Profit, and the Internal Rate of Return as a function of the Percent Annual Water Savings Required for the various heat rejection systems at each of the five studied climatic locations studied. Key results and conclusions are presented.

A hybrid wet-dry cooling system can reduce water consumption at a power plant while minimizing the performance penalty of an air-cooled condenser (ACC). Automatic allocation of turbine exhaust steam among the wet and dry sections provides robust performance. However, the performance test for the unit must be carefully designed to prove the guarantees for water conservation and thermal performance with minimal uncertainty. A hybrid wet-dry cooling system of the “parallel” type is modeled based on recently-constructed power plants. Effects of typical off-design test conditions are demonstrated. Techniques are recommended for designing an effective performance test for a hybrid wet-dry cooling system based on the use of existing Performance Test Codes (PTC).

As noted in a Summer 2007 EPRI Journal article entitled Running Dry At The Power Plant , “Securing sufficient supplies of fresh water for societal, industrial, and agricultural uses while protecting the natural environment is becoming increasingly difficult in many parts of the United States. Climate variability and change may exacerbate the situation through hotter weather and disrupted precipitation patterns that promote regional drought.” Currently, in the United States, thermoelectric power production accounts for approximately 39% of freshwater withdrawals and 3% of overall fresh water consumption. The Electric Power Research Institute, EPRI, as part of its Technology Innovation (TI) program, is collaborating with Johnson Controls to conduct a feasibility study comparing the performance of a water saving Thermosyphon Cooler Hybrid System (TCHS) with other heat rejection systems for power plant applications. The TCHS employs a sensible heat rejection device, a thermosyphon cooler (TSC) in conjunction with an evaporative heat rejection device, an open cooling tower, to satisfy the annual cooling requirements of a given power plant. By reducing the evaporative heat load, the TCHS can significantly reduce the annual water consumed for cooling while still maintaining peak power plant output on the hottest summer days. Operational details of the Thermosyphon Cooler Hybrid System are presented. Additionally an overview of the cooling system simulation program, based on an 8,760 hourly analysis, used in the feasibility study is discussed. Results comparing the water use and additional fan power requirements between power plants employing a traditional all evaporative system and the TCHS are discussed for two different climatic locations. The concept of incorporating the cost of water, cost of power, the current plant operating conditions, and the current ambient dry bulb temperature into the TSC fan control strategy are also explored. The simulation program performance model is currently being validated with testing of a 1MW prototype TCHS at the Water Research Center near Cartersville, GA. Finally, a conceptual design for a power plant scale TCHS is presented.

Ameresco & Department of Energy Savannah River partnered together to install three biomass fueled energy plants. The main plant is a 20 megawatt steam power plant and the other two smaller plants are thermal heating plants. All three facilities are located on the Department of Energy Savannah River Site (SRS). These facilities were developed and financed under an Energy Savings Performance Contract (ESPC), which utilizes energy and operational savings to fund the capital investment and operations cost over the performance period. Ameresco was fully responsible for the design, installation, oversight, management, safety, environmental compliance, and continues to be responsible for the operations and maintenance of the Biomass Cogeneration Facility. This is the largest biomass facility installed under ESPC in the federal government. The facilities have the capacity to combust 385,000 tons of forest residue annually. In the first year alone, the energy and operation cost savings at SRS is in excess of $34 million. Clean biomass and bio-derived fuels (such as tire derived fuel and untreated pallets) is the primary fuel source for all of the new boilers. Biomass is used to fuel two steam boilers capable of producing 240,000 lb. /hr. of high-pressure steam and to power a steam turbine capable of generating up to 20 MW of electricity. The smaller thermal plants provide biomass-produced steam for the areas’ heating and industrial processes. These plants satisfy winter steam requirements for both domestic heat and process steam and is fueled solely with biomass wood chips, utilizing fuel oil as backup source of fuel. Key benefits of the SRS biomass project include: • Over 2,000,000 MBtu/yr. of thermal renewable energy production and a minimum of generation of 77,000,000 kWh of green power • Annual Energy Reductions of approximately 500,000 MBtu/yr. • No-cost Renewable Energy Credits retained by the DOE SR • Support of the South Carolina Biomass Council Goals • Decrease of water intake from the Savannah River by 1,400,000 kgal/yr., supporting water conservation efforts in the region • Reduction of 400 tons/yr. of Particulate Matter (PM) emissions • Reduction of 3,500 tons/yr. of Sulfur Dioxide emissions • Reduction of 100,000 tons/yr. of Carbon Dioxide emissions The smaller heating plants include the main boiler systems and live bottom trailer fuel storage. The Biomass Cogeneration Facility includes the biomass boiler systems, the steam turbine generation system, and the facility auxiliary systems as well as the site infrastructure within these boundaries. The Facility has been designed, built, and tested per industrial/commercial codes for cogeneration facilities. The main components of the Facility are listed below: • Fuel Yard – Material Unloading & Storage and Delivery System ○ Biomass Fuel Chip unloading system ○ Fuel Storage Area ○ Transfer conveyors ○ Fuel Screening System ○ Tire Derived Fuel Storage & Unloading Area ○ Whole Log Chipping System & Storage • Water Treatment System – Water treatment system to treat river water for use in boilers as well as cooling tower for condensing turbine • Boiler Systems – (2) Boiler Island from metering bin, water side and flue gas side, pollution control devices and stacks • Chemical Treatment System – Chemical skids, injection skids for cooling tower and boiler treatment • Steam Turbine Generator System & Turbine Cooling System – (1) steam turbine and generator & Cooling Tower with cooling tower pumps • Emergency Generator System – (1) back diesel generator • Plant Control System – Master SCADA system which integrates all systems and balance of plant equipment I/O into one control system

The paper describes the evolution of a successful new combined cycle utility generation plant over nearly two decades in response to external and internal requirements for commercial, environmental and functional performance. The Afton Project followed an evolutionary path from initial development as a peaking unit into its full realization as an innovative combined cycle station utilizing a hybrid cooling system to realize its owner’s objectives for water conservation and the ability to respond to load demands in the arid Southwest. Afton, a state-of-the-art 225 MW combined cycle facility, entered commercial operation in October of 2007, delivering critically needed capacity with NOx at 3.5 ppm or less.