WRI 50: Strategies for Cooling Electric Generating Facilities Utilizing Mine Water
Power generation and water consumption are inextricably linked. Because of this relationship DOE/NETL has funded a competitive research and development initiative to address this relationship. This report is part of that initiative and is in response to DOE/NETL solicitation DE-PS26-03NT41719-0. Thermal electric power generation requires large volumes of water to cool spent steam at the end of the turbine cycle. The required volumes are such that new plant siting is increasingly dependent on the availability of cooling circuit water. Even in the eastern U.S., large rivers such as the Monongahela may no longer be able to support additional, large power stations due to subscription of flow to existing plants, industrial, municipal and navigational requirements. Earlier studies conducted by West Virginia University (WV 132, WV 173 phase I, WV 173 Phase II, WV 173 Phase III, and WV 173 Phase IV in review) have identified that a large potential water resource resides in flooded, abandoned coal mines in the Pittsburgh Coal Basin, and likely elsewhere in the region and nation. This study evaluates the technical and economic potential of the Pittsburgh Coal Basin water source to supply new power plants with cooling water. Two approaches for supplying new power plants were evaluated. Type A employs mine water in conventional, evaporative cooling towers. Type B utilizes earth-coupled cooling with flooded underground mines as the principal heat sink for the power plant reject heat load. Existing mine discharges in the Pittsburgh Coal Basin were evaluated for flow and water quality. Based on this analysis, eight sites were identified where mine water could supply cooling water to a power plant. Three of these sites were employed for pre-engineering design and cost analysis of a Type A water supply system, including mine water collection, treatment, and delivery. This method was also applied to a ''base case'' river-source power plant, for comparison. Mine-water system cost estimates were then compared to the base-case river source estimate. We found that the use of net-alkaline mine water would under current economic conditions be competitive with a river-source in a comparable-size water cooling system. On the other hand, utilization of net acidic water would be higher in operating cost than the river system by 12 percent. This does not account for any environmental benefits that would accrue due to the treatment of acid mine drainage, in many locations an existing public liability. We also found it likely that widespread adoption of mine-water utilization for power plant cooling will require resolution of potential liability and mine-water ownership issues. In summary, Type A mine-water utilization for power plant cooling is considered a strong option for meeting water needs of new plant in selected areas. Analysis of the thermal and water handling requirements for a 600 megawatt power plant indicated that Type B earth coupled cooling would not be feasible for a power plant of this size. It was determined that Type B cooling would be possible, under the right conditions, for power plants of 200 megawatts or less. Based on this finding the feasibility of a 200 megawatt facility was evaluated. A series of mines were identified where a Type B earth-coupled 200 megawatt power plant cooling system might be feasible. Two water handling scenarios were designed to distribute heated power-plant water throughout the mines. Costs were developed for two different pumping scenarios employing a once-through power-plant cooling circuit. Thermal and groundwater flow simulation models were used to simulate the effect of hot water injection into the mine under both pumping strategies and to calculate the return-water temperature over the design life of a plant. Based on these models, staged increases in required mine-water pumping rates are projected to be part of the design, due to gradual heating and loss of heat-sink efficiency of the rock sequence above the mines. Utilizing pumping strategy No.1 (two mines) capital costs were 25 percent lower and operating cost 19 percent higher than a conventional river-water cooling water scheme. Utilizing pumping strategy No.2 (three mines), capital costs were 20 percent lower and operating costs 192 percent higher. Major capital cost advantages are obtained by using earth-coupled cooling, due in large part to elimination of need for cooling towers. In addition, the lack of cooling towers and of thermal-pollution considerations may be positive factors in power plant permitting. However, application of Type B earth-coupled cooling will be technically feasible limited at a much smaller number of sites than Type A systems due to requirements involving mine size, geometry, and hydraulic conditions. Innovations such as directional drilling may be required to create mine interconnections across barriers where none presently exist.
- Research Organization:
- West Virginia Univ., Morgantown, WV (United States)
- Sponsoring Organization:
- USDOE
- DOE Contract Number:
- FC26-03NT41908
- OSTI ID:
- 881251
- Country of Publication:
- United States
- Language:
- English
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Related Subjects
ACID MINE DRAINAGE
CAPITALIZED COST
COAL MINES
COOLING SYSTEMS
COOLING TOWERS
DIRECTIONAL DRILLING
ECONOMICS
ELECTRIC POWER
EVAPORATIVE COOLING
HEAT SINKS
HOT WATER
OPERATING COST
POWER GENERATION
POWER PLANTS
THERMAL POLLUTION
WATER
WATER QUALITY
WATER RESOURCES
WATER SUPPLY