WorleyParsons has recently been involved in various cogeneration plant studies and projects for district heating, refinery upgrades, and enhanced oil recovery (EOR) applications. In all of them, balancing thermal and power generation was central to optimizing overall plant economics.
In addition to economics, a number of significant design constraints and operational issues must be addressed if a plant is to simultaneously deal with variations in electricity and thermal demand. We have found that the key to success is to systematically evaluate the entire operating regime while assessing potential mitigating options. That is especially the case for combined-cycle cogeneration plants powered in part by midsize or large frame gas turbines.
History's own cycle
For the purposes of this article, we define cogeneration as the simultaneous production of electrical and thermal energy from a single fuel source. The thermal energy, either in the form of steam, hot water, or another heating medium, is typically used for district or process heating and/or cooling. (In Europe, these sources of district heating are called combined heat and power plants.)
In the U.S., cogeneration has a history almost as long as standalone power generation. Most early cogen plants were built by factories that needed both power and steam. With the rise of the central station early in the 20th century, most of these factories found that they could buy electricity more cheaply from their local utility than by generating it themselves. As a result, the overall economics of independent plants that stopped or cut back on private power production suffered. That would not have been the case had utilities connected the private plants to their grids and paid for the generation. But no law forced the utilities to do that, so most didn't, to improve their own bottom lines.
The Public Utility Regulatory Policies Act of 1978 (Purpa) addressed this economic inefficiency by requiring utilities to buy non-utility generating plants' excess electrical output at "avoided cost" (typically, the utility's fuel cost). Depending on its electric to thermal demand ratio, a private plant had to satisfy the minimum annual fuel use efficiency criteria to be considered a "Qualifying Facility." Purpa also created several tax incentives that motivated many thermal energy users to develop small cogeneration plants. All told, Purpa created both financial and accounting burdens for regulated utility monopolies.
Purpa began losing steam in the early 1990s when lucrative power-purchase contracts began to expire. Another nail in its coffin was the Energy Policy Act of 1992, which mandated open access to utility grids, creating a huge market for self-generators. Soon afterward, many states stopped insisting that their utilities buy power from developers of non-utility power projects. Although this represented a setback for cogeneration in the U.S., the scheme lost no momentum in other developed countries, where fuel costs more and governments continue to provide incentives to cogenerators. To complete the story, the Energy Policy Act of 2005 added five new standards to Purpa related to interconnection policies and net metering, among others (www.oe.energy.gov/purpa.htm).
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