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.

An annular superheater element for superheating steam within firetubes of firetube boilers comprising concentric inner and outer tubes and a specially designed return end cap. Saturated steam introduced into the outer tube of said superheater element is superheated while traveling towards the burner end of the tube, is directed into the inner tube by means of the return end cap, and travels away from the burner side of the element where it is exhausted for use as superheated steam. While traversing the inner tube, the superheated steam gives off heat energy through the wall of the inner tube to the steam traveling in the outer tube towards the burner end of the tube, conserving energy. The improved superheater element produces superheated steam more efficiently, with less fuel, and steam capable of doing more work, than conventional superheater elements and can be used to retrofit existing firetube type boilers.

An annular superheater element for superheating steam within firetubes of firetube boilers comprising concentric inner and outer tubes and a specially designed return end cap. Saturated steam introduced into the outer tube of said superheater element is superheated while traveling towards the burner end of the tube, is directed into the inner tube by means of the return end cap, and travels away from the burner side of the element where it is exhausted for use as superheated steam. While traversing the inner tube, the superheated steam gives off heat energy through the wall of the inner tube to the steam traveling in the outer tube towards the burner end of the tube, conserving energy. The improved superheater element produces superheated steam more efficiently, with less fuel, and steam capable of doing more work, than conventional superheater elements and can be used to retrofit existing firetube type boilers.

A gas turbine exhaust heat recovery plant includes a plurality of gas turbine exhaust heat recovery devices that have a gas turbine and an exhaust heat recovery boiler for generating steam by recovering exhaust heat of the gas turbine, a steam-utilizing facility that utilizes the steam generated by the exhaust heat recovery boiler, and an inter-device heat medium supply unit capable of supplying a portion of water heated or a portion of the steam generated by at least one of the gas turbine exhaust heat recovery devices out of the plurality of gas turbine exhaust heat recovery devices, to the other gas turbine exhaust heat recovery device.

Embodiments of the present disclosure can include a system for generating steam. The system can include a direct steam generator configured to generate saturated steam and combustion exhaust constituents. A close coupled heat exchanger can be fluidly coupled to the direct steam generator, the close coupled heat exchanger can be configured to route the saturated or superheated steam and combustion exhaust constituents through an exhaust constituent removal system. The system can include an energy recovery system that reclaims the energy from the exhaust constituents.

Embodiments of the present disclosure can include a system for generating steam. The system can include a direct steam generator configured to generate saturated steam and combustion exhaust constituents. A close coupled heat exchanger can be fluidly coupled to the direct steam generator, the close coupled heat exchanger can be configured to route the saturated or superheated steam and combustion exhaust constituents through an exhaust constituent removal system. The system can include an energy recovery system that reclaims the energy from the exhaust constituents.

A Waste-to-Energy plant comprising: an incineration chamber in which waste is combusted generating flue gas; an economizer heating feedwater using heat from the flue gas; an evaporator producing steam from the heated feedwater using heat from the flue gas; a steam drum receiving heated feedwater from the economizer and supplying heated feedwater, the steam drum receiving steam from the evaporator and supplying steam; and a superheater receiving and heating steam from the steam drum to a superheated steam using heat from the flue gas; the incineration chamber comprising a first PCM-wall and a second PCM-wall each comprising a plurality of pipes and a layer of PCM provided between the pipes and the incineration chamber, the pipes in the first PCM-wall receiving heated feedwater from the steam drum and producing additional steam therein and the pipes of the second PCM-wall additionally heating steam therein using radiant heat from the incineration chamber.

A Waste-to-Energy plant comprising: an incineration chamber in which waste is combusted generating flue gas; an economizer heating feedwater using heat from the flue gas; an evaporator producing steam from the heated feedwater using heat from the flue gas; a steam drum receiving heated feedwater from the economizer and supplying heated feedwater, the steam drum receiving steam from the evaporator and supplying steam; and a superheater receiving and heating steam from the steam drum to a superheated steam using heat from the flue gas; the incineration chamber comprising a first PCM-wall and a second PCM-wall each comprising a plurality of pipes and a layer of PCM provided between the pipes and the incineration chamber, the pipes in the first PCM-wall receiving heated feedwater from the steam drum and producing additional steam therein and the pipes of the second PCM-wall additionally heating steam therein using radiant heat from the incineration chamber.

The method in a recovery boiler comprises estimating the first melting temperature T.sub.0 of the fly ash depositing on heat transfer surfaces, the estimating being based on potassium (K) content of the fly ash; measuring or estimating the temperature T.sub.ss of superheated steam; evaluating a temperature difference T.sub.D1 between the first melting temperature T.sub.0 and the temperature T.sub.ss of the superheated steam, the temperature difference T.sub.D1 providing an estimate of the risk of corrosion; and selecting a control action for influencing the temperature difference T.sub.D1. Alternatively or additionally, the method comprises estimating the sticky temperature T.sub.STK of the fly ash depositing on heat transfer surfaces, the estimating being based on potassium (K) and chlorine (Cl) contents of the fly ash; measuring or estimating the temperature T.sub.FG of the flue gases; evaluating a temperature difference T.sub.D2 between the sticky temperature T.sub.STK and the temperature T.sub.FG of the flue gases; the temperature difference T.sub.D2 providing an estimate of the risk of plugging; and selecting a control action for influencing the temperature difference T.sub.D2.

The method in a recovery boiler comprises estimating the first melting temperature T.sub.0 of the fly ash depositing on heat transfer surfaces, the estimating being based on potassium (K) content of the fly ash; measuring or estimating the temperature T.sub.ss of superheated steam; evaluating a temperature difference T.sub.D1 between the first melting temperature T.sub.0 and the temperature T.sub.ss of the superheated steam, the temperature difference T.sub.D1 providing an estimate of the risk of corrosion; and selecting a control action for influencing the temperature difference T.sub.D1. Alternatively or additionally, the method comprises estimating the sticky temperature T.sub.STK of the fly ash depositing on heat transfer surfaces, the estimating being based on potassium (K) and chlorine (Cl) contents of the fly ash; measuring or estimating the temperature T.sub.FG of the flue gases; evaluating a temperature difference T.sub.D2 between the sticky temperature T.sub.STK and the temperature T.sub.FG of the flue gases; the temperature difference T.sub.D2 providing an estimate of the risk of plugging; and selecting a control action for influencing the temperature difference T.sub.D2.