The purpose of the present invention is to decrease the loss of energy of flue gas when superheated steam is cooled and prevent heat efficiency from being decreased. A boiler is provided with: economizers (a medium-pressure economizer (13) and a high-pressure secondary economizer (18)) which heat water supplied by water supply pumps (a medium-pressure water supply pump (27) and a high-pressure water supply pump (28)); evaporators (a medium-pressure evaporator (16) and a high-pressure evaporator (21)) which evaporate the water that is heated by the economizers; and cooling devices (a medium-pressure system and a high-pressure system) which mix water, as a coolant, which has passed through the economizers via the water supply pumps with steam.

The purpose of the present invention is to decrease the loss of energy of flue gas when superheated steam is cooled and prevent heat efficiency from being decreased. A boiler is provided with: economizers (a medium-pressure economizer (13) and a high-pressure secondary economizer (18)) which heat water supplied by water supply pumps (a medium-pressure water supply pump (27) and a high-pressure water supply pump (28)); evaporators (a medium-pressure evaporator (16) and a high-pressure evaporator (21)) which evaporate the water that is heated by the economizers; and cooling devices (a medium-pressure system and a high-pressure system) which mix water, as a coolant, which has passed through the economizers via the water supply pumps with steam.

A system for deriving 100% quality steam for steam assisted gravity drainage (SAGD) injection or other applications features a once through steam generator (OTSG), a steam-water separator connected downstream of the OTSG's radiant tubes to separate steam and water from a two-phase flow received therefrom, superheater tubes installed in the convection section and connected to a steam outlet of the steam-water separator in downstream relation thereto to receive and heat dried steam therefrom to a superheated state, and a desuperheater connected downstream of the superheater tubes to receive the superheated steam therefrom and use same to vaporize blowdown water from the steam-water separator, whereby the vaporized blowdown water and the superheated steam collectively form a superheated steam output for the intended application, typically after additional separation of solid particles therefrom for optimal steam quality.

A control device includes a reception unit that receives a load schedule indicating a load in the future of a combined cycle plant, a steam temperature control unit that controls a temperature of steam flowing into a steam turbine, and a fuel control unit that controls a flow rate of fuel supplied to a gas turbine. The steam temperature control unit outputs a command indicating an amount of operation for decreasing the temperature of the steam to a steam temperature regulator prior to a load decrease time at which the load is to be decreased in the load schedule.

A control device includes a reception unit that receives a load schedule indicating a load in the future of a combined cycle plant, a steam temperature control unit that controls a temperature of steam flowing into a steam turbine, and a fuel control unit that controls a flow rate of fuel supplied to a gas turbine. The steam temperature control unit outputs a command indicating an amount of operation for decreasing the temperature of the steam to a steam temperature regulator prior to a load decrease time at which the load is to be decreased in the load schedule.

A steam supply system having a wet steam source and a steam separator disposed to separated wet steam into dry saturated steam and a saturated condensate. The dry saturated steam is heated in a superheater to produce superheated steam, while the saturated condensate is cooled in a subcooler to produced subcooled condensate with a target temperature selected to prevent immediate evaporation of the subcooled condensate when mixed with the superheated steam. The subcooled condensate is sprayed into a stream of superheated steam using spray nozzles and gradually evaporates downstream of the spray nozzles to produce process steam of a desired % quality. A cooling fluid passing through the subcooler is utilized to cool the saturated condensate. The flow rate of the cooling fluid through the subcooler can be utilized to achieve process steam of a desired % quality.

A steam supply system having a wet steam source and a steam separator disposed to separated wet steam into dry saturated steam and a saturated condensate. The dry saturated steam is heated in a superheater to produce superheated steam, while the saturated condensate is cooled in a subcooler to produced subcooled condensate with a target temperature selected to prevent immediate evaporation of the subcooled condensate when mixed with the superheated steam. The subcooled condensate is sprayed into a stream of superheated steam using spray nozzles and gradually evaporates downstream of the spray nozzles to produce process steam of a desired % quality. A cooling fluid passing through the subcooler is utilized to cool the saturated condensate. The flow rate of the cooling fluid through the subcooler can be utilized to achieve process steam of a desired % quality.

A steam-temperature control device for a gas- and steam turbine plant, including a feed water line, a feed-water control valve located in the feed water line and a water injection line which branches off from the feed water line upstream of the feed-water control valve in the flow direction of said water and which opens into an injection cooler is provided. The steam-temperature control device is characterized in that a pre-heating device for the injection water is connected in the water injection line. A method for controlling the steam temperature in a gas- and steam turbine plant is also provided.

A steam-temperature control device for a gas- and steam turbine plant, including a feed water line, a feed-water control valve located in the feed water line and a water injection line which branches off from the feed water line upstream of the feed-water control valve in the flow direction of said water and which opens into an injection cooler is provided. The steam-temperature control device is characterized in that a pre-heating device for the injection water is connected in the water injection line. A method for controlling the steam temperature in a gas- and steam turbine plant is also provided.

Embodiments of systems and methods described in this disclosure are directed to operating a combined cycle power plant. In certain embodiments, systems and methods can be provided for a combined cycle power plant incorporating a control system that uses a holistic approach to continuously and automatically adjust a heat rate of the combined cycle power plant and achieve a desired efficiency. In accordance with one embodiment of the disclosure, the control system can be used to dynamically control various operations of the combined cycle power plant, including addressing of certain conflicting requirements such as avoiding generation of superheated steam in an attemperator while concurrently maintaining exhaust emissions within allowable regulatory limits and maintaining exhaust gas temperatures within allowable material capability limits. The use of such a control system allows for an increased turndown capability of the combined cycle power plant along with an improvement in a combined cycle heat rate of the combined cycle power plant.