Westinghouse Electric Corporation

The United States of America As Represented by the Department of Energy

The United States of America As Represented by the United States Energy

Siemens Corporation

David H Archer

M Mushtaq Ahmed

Edward J Vidt

Thomas E Lippert

Frank I Bauer

David F Ciliberti

Chellury R Sastry

William E Young

Mark C Williams

James R Hamm

Mohammed M Ahmed

John G Wimer

Viraj Srivastava

Joseph L Chen

Richard H Lunn

M Mustaq Ahmed

A controller for controlling thermal sources affecting an air temperature in a space subjected to thermal variables, including a sensor network measuring the thermal variables; a feed forward controller generating a feed forward control signal based on an adaptive model including a model of the space and a model of the thermal sources, wherein the models are formed utilizing data from the sensor network; a feedback controller generating a feedback control signal based on a difference between an output of the feed forward controller and output from the space; and a combiner combining the feed forward and feedback control signals to produce a control signal for controlling the thermal sources to control the air temperatures of the space.

Apparatus and method for the control of the indoor thermal environment having feed forward and feedback control using adaptive reference models

An improved electrochemically active system and method including a plurality of electrochemical devices, such as fuel cells and fluid separation devices, in which the anode and cathode process-fluid flow chambers are connected in fluid-flow arrangements so that the operating parameters of each of said plurality of electrochemical devices which are dependent upon process-fluid parameters may be individually controlled to provide improved operating efficiency. The improvements in operation include improved power efficiency and improved fuel utilization in fuel cell power generating systems and reduced power consumption in fluid separation devices and the like through interstage process fluid parameter control for series networked electrochemical devices. The improved networking method includes recycling of various process flows to enhance the overall control scheme.

System and method for networking electrochemical devices

A method and apparatus for modeling flow in a bunker detects material characteristics of material supplied to a bunker and predicts the type of flow from the sensed material characteristics. Material characteristics of the material subsequently discharged from the bunker are compared with the material characteristics of the material supplied to the bunker to verify the prediction of flow in the bunker. The method and apparatus can be applied to bunkers storing coal at a power plant where moisture content, heating value, sulphur, etc. are detected by a bulk material analyzer prior to being supplied to a plurality of bunkers. Even if the coal is subsequently mixed prior to combustion, estimates, an be made of the contribution of each bunker to the resulting heating value, moisture removed, sulphur, ash content, etc. An appropriate flow model predicting one of mass flow, rat hole flow and funnel flow can be selected based upon characteristics of the material supplied to and discharged from the bunkers.

Method and apparatus for modeling bunker flow

Boiler operations are fine tuned to minimize thermodynamic losses and pressure losses across throttle valves at the output of a boiler. Whenever the boiler is operating outside of desired operating levels, the first action considered is to reduce spray flows into steam supplied into a reheater or superheater outputting steam at too low of a temperature. The second consideration is to reduce the use of auxiliary electrical power, such as fans supplying tempering air to the primary air used to carry fuel to the burners. The next consideration is selective soot blowing and damper adjustments to redistribute heat in combustion product exhaust gas in the boiler. Then, if possible, the quantity of flue (combustion product) as recycled is adjusted to modify the gas temperature and the heat transferred in the radiant (furnace and superheat) sections and the convective (reheat and economizer) sections of the boiler. Finally, when possible the burners are tilted or biased to move a combustion region of the fuel up or down in the furnace section of the boiler. Burner vanes are set affecting fuel-air mixing and pulverizers are adjusted modifying fuel particle size to alter both the size and position of the combustion region in the boiler. An expert system may be used to provide diagnostics and advisories to a human operator of the boiler who can then more efficiently operate the boiler.

Method and apparatus for optimized boiler operation

A method for determining the concentration of a plurality of combustible gases in a gas stream comprises providing an electrochemical cell apparatus that includes an electrochemical cell in which a cavity is formed having a diffusion limiting port forming the entrance to the cavity. The cell has a process side in flow communication with a portion of the gas stream flowing into the cavity through the port, and a reference side in flow communication with a reference gas. The process side and the reference side of the electrochemical cell are separated by an electrolyte. The potential difference across the cell is adjusted to create a steady state electrical current flow. A number of the following current flow measurements are obtained, wherein the number of current flow measurements equals the number of combustible gases in the gas stream: determining the steady state current flowing through the electrolyte, and determining the surge of current flowing through the electrolyte after the flow of current is interrupted and then restored, by interrupting the current for a time period, restoring the flow of current and measuring the surge of current until the current attains its steady state value. The total pressure of the gases in the gas stream is measured, and the total pressure and the current flow measurements are converted into an indication of the concentration of each of the combustible gases in the gas stream.

Method for determining the concentration of a plurality of combustible

A system and method for controlling the operation of a steam condenser in a power plant which includes a steam turbine, the condense having: a steam flow path including a steam inlet connected to receive turbine exhaust steam from the turbine steam outlet, a condensate outlet and a heat exchange region located between the steam inlet and the condensate outlet; a cooling water flow path having an inlet and an outlet and heat exchange elements for conducting cooling water through the heat exchange region, and a non-condensible product removal path having an inlet communicating with the heat exchange region and an outlet located outside of the heat exchange region. Control is effected by: measuring fluid flow at the steam inlet, the condensate outlet, the cooling water inlet and the cooling water outlet; providing a computer model of the condenser in its normal operating condition, supplying the model with representations of the measured flows at the steam inlet and the cooling water outlet, and producing, in the model, indications of the flow at the condensate outlet and the cooling water outlet when the condenser is in its normal operating condition; comparing the indications from the producing step with the measured flow at one of the condensate outlet and the cooling water outlet from the measuring step; and effecting a computerized analysis of the result of the comparing step for providing an indication of the probable cause of differences between the compared indications and flows.

Power plant condenser control system

A system and method for controlling soot removal in a heating device (2) in which heat energy is generated by combustion of a fuel, with accompanying production of soot, to produce combustion product gases, and heat energy is transferred from the product gases to a heated medium via a heat exchange surface on which the soot collects in a layer, by: producing (10) an indication of the present thickness of the soot layer; determining (12) the increase in cost of transferring heat energy to the heated medium due to the soot layer; and performing (4) a soot removal operation starting at a time selected on the basis of the determined cost increase.

Method for soot blowing automation/optimization in boiler operation

A system for monitoring combustion of coal in a boiler detects coal composition and heating value using a bulk material analyzer and determines an air/fuel mixture so that when the coal is burned oxygen is available throughout the boiler and the wall temperature of the boiler is maintained below the metallurgical limit and the surface temperature below the ash fusion temperature of the coal where slagging is not desired. The temperature and pressure of steam in the boiler, fuel and air flow rates and temperature and oxygen content of the stack gases are supplied to a boiler model. The boiler model predicts how varying the air supply rate affects sensible heat loss. Periodic measurements of unburned carbon in the ash produced by combustion of the coal are correlated with the operation of the boiler at the time that the ash was produced to provide a basis for estimating unburned coal loss. An optimum air/fuel mixture is determined to minimize heat loss for a given steam production rate or to maximize steam production, using the estimate of unburned carbon loss and output from the boiler model, while at all times maintaining sufficient air flow to prevent oxygen depletion and acceptable wall temperatures.

System for optimizing total air flow in coal-fired boilers

An improvement in a process for operating a gas turbine system containing a compression unit, a combustion unit and an expansion unit to operate a generator, wherein a low BTU gaseous fuel is used in the combustion unit and a portion of the air from the compression unit is bled from the system so as to prevent surges in the compression unit by limiting the flow of combustion gases to the compression unit, which comprises heating the air charged to the compression unit so as to reduce the volume of air from the compression unit that is bled from the system, and thereby increase the efficiency of the gas turbine system.

Method for increasing the efficiency of gas turbine generator systems

A method for electric power production or cogeneration of electrical power and process heat and/or steam that integrates a solid carbonaceous fuel gasification system and gas turbine system. Fuel gas produced in the gasification system is combusted and the combustion gases used in the gas turbine system. The gas turbine system uses water spray intercooling of the compressor or compressors, with air-water mixture from the compressor used in the gasification system, while hot exhaust gas from the turbine system has heat recuperated therefrom and is used to produce steam, which is also used in the gasification system.

Method for energy conversion

Electric power is produced in an electric power generating combustion turbine using a biogas as fuel thereto, where a biogas, leaving a biomass gasification system at an elevated temperature of 650.degree.-875.degree. C. and containing tars, is partially cooled by injection of a spray of water thereto to a lower temperature of about 260.degree.-555.degree. but above that which would condense tars. The partially cooled biogas stream is then filtered to remove solid particulate matter therefrom and is directly charged as fuel to the electric power producing combustion turbine for the production of electric power.

Process for electric power production using a biogas

A waste disposal system for the combustion of waste materials, that may include toxic chemical waste, wherein the wastes are combusted in a combustion unit with combustion gases directly discharged into a refractory lined housing having a plurality of ceramic filters disposed in the gas outlet wall thereof. The combustion gases are maintained in the refractory lined housing for a period of time sufficient to effect combustion of the major portion of residual vaporous waste constituents therein and then passed through the ceramic filters to remove the remainder of said vaporous waste constituents and the residual solid waste constituents. The waste-free, hot combustion gases, after passage through the filters, are directed to a heat exchanger for recovery of heat values therefrom. Soils contaminated with a toxic chemical waste may be decontaminated by charging the soil as a portion of a combustible waste charge to the combustion unit, with the toxic chemical waste subjected to combustion, with the resultant decontaminated soil, along with ash from the combustible waste used as a landfill.

Apparatus and method for disposal of hazardous waste material

High temperature corrosion and erosion resistant electrodes particularly useful for magnetohydrodynamic generators which electrodes utilize chemical ionization of combustion reactants to diffuse the current flow into the electrode. A combustible fuel, oxidant and electrically conductive material flow through porous, graded electrode components toward the plasma. Catalyzed combustion occurs near the face of the electrode exposed to the plasma which diffuses current transfer in the boundary layer and into the electrode. The reactants and combustion products thus combine simultaneously to cool the inner portions of the electrode, heat the outer portions, protect the exposed electrode surface from erosion, and alleviate the physical or chemical bonding of the by-products of coal combustion to the electrode surface which otherwise results in chemical degradation of the electrode.

High temperature corrosion and erosion resistant electrode

Raw shale is supplied to a pyrolyzer where it is pyrolyzed by fuel gas and hot spent shale derived from a gasifier. Typically, the raw shale is Eastern U.S. shale and the pyrolyzer includes a fluidized bed. The pyrolyzed shale having given up its oil and volatile hydrocarbons, rises to the top of the fluidized bed of raw shale where it is transferred to the gasifier. Oxygen and steam are supplied to the gasifier. This composite gas reacts with the carbon of the pyrolyzed shale in a fluidized bed to produce synthesis or fuel gas. The oxygen is supplied in such quantities as not to react completely with the carbon in the pyrolyzed shale. The steam reacts with the excess of carbon. Predominantly hydrogen and carbon monoxide are produced; in addition there is a smaller quantity of carbon dioxide and methane. This hot fuel gas is transferred to the pyrolyzer. In addition, hot spent shale is transferred to the pyrolyzer. The hot fuel gas fluidizes the raw shale in the pyrolyzer. The hot gas and the hot spent shale heat the raw shale separating the shale oil and product gas including volatile hydrocarbons. The oil is condensed and collected, the fuel gas is collected for utilization in the above process and also for other purposes.

Recovery of fuel from oil shale

A method and apparatus for gasifying coal wherein the gasification takes place in a spout fluid bed at a pressure of about 10 to 30 atmospheres and a temperature of about 1800.degree. to 2200.degree.F and wherein the configuration of the apparatus and the manner of introduction of gases for combustion and fluidization is such that agglomerated ash can be withdrawn from the bottom of the apparatus and gas containing very low dust loading is produced. The gasification reaction is self-sustaining through the burning of a stoichiometric amount of coal with air in the lower part of the apparatus to form the spout within the fluid bed. The method and apparatus are particularly suitable for gasifying coarse coal particles.

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Pittsburgh, PA, United States of America

David H Archer