The present disclosure includes an optical measuring system having at least one light source that radiates excitation light into a medium to be measured. The excitation light is converted into fluorescent light by the medium. The optical measuring system also includes a first photodiode that receives a decay curve of the fluorescent light and converts it into a first signal and at least one optical component that receives the fluorescent light and converts it into a second signal. A data processing unit determines an oil-in-water content based on the first signal and the second signal.

The present invention relates to a system for detecting deposits or chemical inhibitor close to or on the surface of electrodes or pins facing a fluid flow where any combination of the components oil, water, gas and a chemical inhibitor fluid could be present, and where the electrodes or pins are coupled to measuring means for monitoring the electrical characteristics of the flow, the electrical characteristics including the complex impedance or complex permittivity. The system comprises detecting means transmitting a signal indicating presence of deposit or chemical inhibitor if the real part of the complex impedance, in case of hydrocarbon continuous flow, or the imaginary part of the complex impedance, in case of water continuous flow deviates from predetermined limits related to the electrical characteristics of the said flow.

Devices, methods, and systems employing a multivariate optical computing sensor comprising a multivariate optical element calibrated to independently measure an electromagnetic spectral pattern of a cultivation characteristic of an algae stain in a cultivating algae water slurry and a detector for receiving output signals indicative of the cultivation characteristic. The cultivation characteristic may include, for example, total organic carbon, total carbohydrate, or fatty acid methyl esters.

Hydrocarbon condensate detection and control. The hydrocarbon condensate detection and control system includes detecting hydrocarbon in an aqueous mixture by sensing fluorescence, turbidity, and color of the aqueous mixture and controlling the flow of the aqueous mixture based on the hydrocarbon content of the aqueous mixture.

Systems and methods are provided for determining a content of a hydrocarbon or other compound, such as a C.sub.3 to C.sub.7 hydrocarbon, in a condensed steam sample. Cooled steam condensate can be flowed through a sample chamber including an inner overflow tube. When the flow stops, water can be drained from the sample chamber, and then the sample chamber can be opened to allow fluid communication with a vapor chamber above the sample chamber. This can allow hydrocarbons in the condensed steam (and/or other gas) to be transferred from the sample chamber into the vapor chamber. The vapor chamber can then be isolated from the sample chamber. At least a portion of the content of the vapor chamber can then be passed to a detection volume, such as the characterization cell for a gas chromatography system.

Described herein are methods and systems, and techniques relating to hydrocarbon-bearing formation testing and, particularly, to estimating a formation condition. The disclosed methods, systems, and techniques allow for improved prediction of the formation condition and cleanout of the formation following well drilling. In some cases, the disclosed methods, systems, and techniques include using a formation testing tool to obtain a sampled fluid from a formation according to a set of sampling parameters and using the formation testing tool to analyze the sampled fluid to identify a set of fluid parameters for the sampled fluid. A numerical model may be used to determine a formation condition with inputs including the sampling parameters and the fluid parameters.

A method is implemented to determine a concentration of oil in a water sample. A specified amount of cyclohexane is added to the water sample to form a mixture. The mixture is stirred. An oil phase is extracted from the mixture. An absorbance value of the extracted oil phase is measured at a specified wavelength in the visible light spectrum. The specified wavelength is in a range of from 390 nanometers (nm) to 600 nm. The concentration of oil in the water sample is determined based on the measured absorbance value of the extracted oil phase.

An optical sensor for determining the concentration of polycyclic aromatic hydrocarbons in a medium incudes a light source configured to emit transmitted light having a wavelength of less than 300 nm into the medium; a detector for receiving received light, wherein the detector is configured at least for receiving received light having a wavelength of 300 nm to 400 nm, wherein the transmitted light is converted into received light by means of fluorescence in the medium as a function of the concentration of polycyclic aromatic hydrocarbons, wherein a detector signal is generated from the received light; and a data processing unit configured to determine the concentration of polycyclic aromatic hydrocarbons using the detector signal, wherein the data processing unit controls the light source such that the light source emits modulated transmitted light according to a duty cycle. Methods of using the optical sensor are further disclosed.

A method for quantifying a crude oil in water is provided. The method includes selecting an ultraviolet/visible (UV/Vis) wavelength to perform a measurement, preparing calibration solutions in xylene, and preparing a calibration curve from the calibration solutions. A sample is prepared including extracting the crude oil from the water in a two-phase separation with xylene. An absorbance of the sample in the xylene is measured at the UV/Vis wavelength. A concentration of the crude oil in the water is calculated from the absorbance.

A method can include receiving, by a demulsifier analysis framework, tensiometer data for an oil and water field sample that includes an added candidate demulsifier, where the tensiometer data include rheology data with respect to frequency and where the demulsifier analysis framework includes a model derived at least in part on bottle test data for demulsifiers in oil and water emulsions; determining a performance characteristic for the candidate demulsifier with respect to the oil and water field sample using the tensiometer data as input to the model of the demulsifier analysis framework without performing a bottle test on the oil and water field sample; and outputting, by the demulsifier analysis framework, the performance characteristic for the candidate demulsifier with respect to breaking an emulsion of the oil and water field sample.