Subsections
First, the nature of a given facility's operation must be studied. If the facility does not have similar electrical and thermal loads, then a cogeneration system may not be well suited. Also, if either of the loads is highly transient in nature, specific and detailed analysis must be performed concerning the types of equipment capable of following such loads.
Fuel availability affects the type of cogeneration system selected. The nature of the industry choosing to cogenerate will often determine the fuel type, and thereby the cogeneration system. Pollution concerns must be considered as well. States are beginning to heavily regulate industrial emissions. Clean burning fuels, either natural gas or light grade fuel oils, will often be required in these states. Cogeneration systems which most effectively utilize these fuels will probably prove to be the most economically attractive.
The base system analyzed in the theoretical analysis consisting of a gas fired boiler with the purchase of utility electricity is typical of the systems currently installed in many facilities operating today. The operating cost of the gas boiler system was used to normalize the operating cost of all the other systems. The results could then be directly compared. As electricity becomes more expensive in relation to gas, the electrical boiler system quickly became too expensive for further consideration. Unless specific industrial processes require an electric boiler, the electric boiler system should not be used.
Of the 5 systems considered, the reciprocating engine system returned the highest fuel-to-electrical efficiency. For a given set of operational parameters, the return on this system from electrical savings will be greatest. However, the quantity and thermal quality of the heat available for recovery is much lower than the gas turbine and steam turbine systems since a considerable portion of the heat exits in the coolant system.
For smaller applications or applications with transient load profiles, the reciprocating engine is well suited. Packaged cogeneration systems with reciprocating engines as prime movers are commonly available in a wide array of sizes. These systems can be quickly and easily installed with a minimum of on-site engineering.
The steam turbine system had the lowest fuel-to-electrical efficiency of the systems considered. Steam turbines are best suited for systems with a high thermal-to-electrical usage ratio. Steam turbines are generally inexpensive and available in many sizes. For facilities that already generate high pressure steam, steam turbines can be used to replace pressure reducing valves for the recovery of free electricity. This electricity is available because many facilities generate steam at a higher than required pressure then throttle the steam down to a lower delivery pressure. Throttling the steam in this manner wastes valuable energy that can be recovered by a steam turbine.
The gas turbine cogeneration system had close to the same fuel-to-electrical efficiency as the reciprocating engine system, but because the thermal energy exits at such a high temperature it is much more easily recovered. If required, the exhaust may be used as combustion air for further firing in a HRSG due to the high oxygen content of the gas turbine exhaust. The gas turbine has as long a life span as any system considered and the maintenance and supervision costs are low. Also, because gas turbine generator systems come prepackaged (for smaller sized systems), installation expenses are relatively low.
Based on the energy usage characteristics of the Georgia Tech campus, a gas turbine cogeneration system was chosen for further study. The magnitude of the electrical demand exceeds that generally taken as a maximum for reciprocating engine systems (~3 MW), and the low thermal-to-electrical demand of the campus would severely limit the amount of electricity available from a steam turbine system sized to meet the campus thermal load.
Four sizes of gas turbine systems were chosen for the study with each turbine operated under three different operational strategies. A 10 MW, 7.5 MW, 5 MW, and 4 MW were each used for analysis. The 10 MW unit is the largest gas turbine generator that could be operated under a base load strategy, and the 4 MW unit is the smallest turbine size before the price for turbines on a dollar per kW basis becomes prohibitive.
The first of the three operational strategies, the base load strategy, requires that the turbines operate fully loaded at all times. The exhaust is routed to a heat recovery boiler where it produces steam. The steam is used to meet the campus thermal load. Any shortfall in steam is met by the current central boiler system
The peaking strategy requires that the turbines operate only when the cost for RTP electricity exceeds a given value. This value is calculated by determining the cost for producing one kW of electricity using the gas turbine cogenerator for a given a cost of natural gas. If the RTP price for a given hour exceeds the "break even" cost, the generator is turned on. Otherwise, the generators are not operated. As in the base load strategy, the exhaust is used to meet the campus thermal load.
Finally, the thermal following strategy requires that the gas turbines operate such that the recovered thermal energy taken from the HRSG exactly meets the thermal load of the campus. Whatever electricity that can be generated under this operational strategy is used to offset electrical purchases from the electric utility. During the winter months, the turbines will be unable to meet the campus thermal load. The currently installed boiler system will make up the shortfall.
From the economic analysis performed, the base load strategy returned the best economic results. Any of the turbine sizes would have a simple payback of less than six years, a value which seems reasonable for the large scale nature of a cogeneration project. The turbines operate at full load, which minimizes maintenance and supervision costs, maximizes the life span of the unit, and returns the best fuel-to-electrical efficiency.
The 5 MW gas turbine returned the best economic results. The actual payback was 4.1 years, or a 36% return on investment assuming a 15 year life energy cost escalation of 10%, a very attractive number. The 5 MW unit benefits from a relatively low installed cost and a better than average thermal recovery.
The other two operational strategies returned less attractive economic results. The peaking strategy suffered from both low operating hours and poor benefits gained from the electrical rate structure. The CBL cannot be lowered unless the gas turbine is operated continuously. The peaking turbine offsets cheaper RTP electricity. Also, the peaking turbines only operate for 370 hours per year. These two factors combine to return a simple payback of approximately 30 years for each of the four turbine sizes chosen.
The final operational strategy, thermal following, performed better than the peaking strategy, yet not as well as the base loading strategy. Due to the increased load factors of the smaller turbines, the payback for the thermal following strategy improved as the turbine size decreased. In fact, at 2.3 MW, the gas turbine reaches a completely loaded condition, meaning it is fully loaded both thermally and electrically. But, the increasing cost on a dollar per kW basis of the smaller turbines increases their payback.
Of course there are other considerations besides just economic ones. Georgia Power has a considerable amount of interest in maintaining Georgia Tech as a power customer. Georgia Power has been a long time supporter of Georgia Tech and the political influence they wield within the state would act to limit the attractiveness of a cogeneration system on Campus. It is not within the scope of this project to address these types of concerns, but they should be considered.