Abstract: The present disclosure provides a burner management system (BMS) for an industrial gas appliance and method for controlling a warm-up operation of the industrial gas appliance. The BMS and control method only requires a subset of the burners to be provided with flame detectors. In accordance with one aspect, the method involves lighting a supervised burner by providing a fuel gas flow thereto; continuously detecting a flame at the supervised burner indicating that the supervised burner is lit; incrementally lighting non-supervised burners by providing the fuel gas flow thereto when a non-supervised burner status indicates a safe lighting condition, the non-supervised burner status being determined by: measuring a total fuel gas flowing to the plurality of burners; and determining the number of the non-supervised burners with the fuel gas flowing thereto from the measurement of the total fuel gas and a supervised burner status.

Abstract: Method and apparatus for enhancing the combustion of a process gas of variable composition which gas is used for steam generation in producing heavy oil. The mass flow of the process gas containing hydrocarbons, carbon dioxide and water is measured. It is assumed that the process gas is saturated with water vapor and the water content of the process gas is then obtained. The content of carbon dioxide in the process gas is nominally obtained with an oxygen analyser measuring the flue gas from a steam generator thereby giving a close approximation of hydrocarbon content and allowing an expedited calculation of the energy content and air required. The nominal carbon dioxide value is compared with the calculated carbon dioxide value based on the actual flow of process gas and purchase gas and the oxygen content so that the quantity of carbon dioxide is approximated.

Abstract: Method and apparatus for enhancing the combustion of a process gas of variable composition which gas is used for steam generation in producing heavy oil. The mass flow of the process gas containing hydrocarbons, carbon dioxide and water is measured. It is assumed that the process gas is saturated with water vapor and the water content of the process gas is then obtained. The content of carbon dioxide in the process gas is nominally obtained with an oxygen analyser measuring the flue gas from a steam generator thereby giving a close approximation of hydrocarbon content and allowing an expedited calculation of the energy content and air required. The nominal carbon dioxide value is compared with the calculated carbon dioxide value based on the actual flow of process gas and purchase gas and the oxygen content so that the quantity of carbon dioxide is approximated.

Abstract: Method and apparatus used to calculate the hydrogen sulfide and carbon dioxide loading of both rich and lean amine solutions used to remove acidic gas components from sour or production gases in order to produce a sweet or sales gas for transmission purposes. The amine solution is divided into three (3) liquid streams carrying different proportions of heat stable salts, hydrogen sulfide and carbon dioxide. Conductivity measurements are made on each of the streams and are converted to acid loading values for the amine. The acid loading values of the amine are used to obtain the hydrogen sulfide and carbon dioxide loading for the amine solution.

Abstract: Method and apparatus used to calculate the hydrogen sulfide and carbon dioxide loading of both rich and lean amine solutions used to remove acidic gas components from sour or production gases in order to produce a sweet or sales gas for transmission purposes. The amine solution is divided into three(3) liquid streams carrying different proportions of heat stable salts, hydrogen sulfide and carbon dioxide. Conductivity measurements are made on each of the streams and are converted to acid loading values for the amine. The acid loading values of the amine are used to obtain the hydrogen sulfide and carbon dioxide loading for the amine solution.

Abstract: Apparatus and method for determining the water content of an oil and water mixture such as is transported by pipelines and which oil and water may vary in density from time to time. A densitometer measures the density of the oil and water mixture in the pipeline and a value for the dielectric constant of the oil is obtained from the density measurement by correlating the density reading with a capacitance or dielectric constant reading from an empirically generated chart. A basal sediment and water instrument measures the dielectric constant of the same mixture. The difference between the two dielectric constants is then obtained. This result is converted directly into a water based percentage by volume of the oil-water mixture being carried by the pipeline.