Patent ID: 9546959
Date: 2017-01-17
CPC Classifications: E21B,G01N

Claim:
1. A method of characterizing hydrogen sulfide in petroleum fluid of a reservoir traversed by a subterranean wellbore, the method comprising: (a) locating a downhole apparatus within the subterranean wellbore, the downhole apparatus including a fluid admitting assembly for acquiring a live oil sample of the petroleum fluid of the reservoir and a fluid analyzer for performing downhole fluid analysis of the live oil sample, wherein the fluid analyzer comprises a storage chamber fluidly coupled to a measurement chamber, wherein the storage chamber stores an analytical reagent that can be supplied to the measurement chamber, and a flowline that holds the live oil sample, wherein the flowline is fluidly coupled to the measurement chamber; (b) using the fluid admitting assembly to acquire a live oil sample of the petroleum fluid of the reservoir; (c) using the fluid analyzer to perform downhole fluid analysis of the live oil sample to determine properties of the live oil sample, the properties including concentration of carbon dioxide in the live oil sample; (d) producing an oil-water emulsion in the measurement chamber by mixing the fluid of the live oil sample and the analytical reagent using a fluid agitator positioned in the measurement chamber, wherein the oil-water emulsion includes fluid of the live oil sample and the analytical reagent supplied from the storage chamber, wherein the analytical reagent changes color due to changes of pH that arise from chemical reactions between components of the live oil sample and the analytical reagent in the measurement chamber; (e) allowing for separation of the oil-water emulsion into an oil phase and a water phase, the oil phase including the fluid of the live oil sample, and the water phase including the analytical reagent; (f) providing an optical sensor that measures optical density of the water phase at one or more determined wavelengths, wherein the optical sensor is disposed about a portion of the measurement chamber that holds the water phase, and wherein a bottom portion of the measurement chamber holds the water phase; (g) determining via a data processing system a measurement of pH of the water phase based upon the optical density measured in (f); (h) selecting via the data processing system a thermodynamic model that includes terms for pH of the water phase, concentrations of carbon dioxide components, and hydrogen sulfide components that are dissolved in the water phase, wherein contribution of the carbon dioxide components to the pH of the water phase is determined from the concentration of carbon dioxide in the live oil sample as measured in (c); and (i) calculating via the data processing system a concentration of hydrogen sulfide in the live oil sample using the measurement of pH of the water phase of (g), the concentration of carbon dioxide in the live oil sample of (c), and the selected thermodynamic model.