A method for degassing a microfluidic droplet by combining electrowetting and heating to induce formation of gaseous bubbles in the droplet. In an embodiment the methods are carried out on an active matrix of electrowetting electrodes including a hydrophobic coating. A carrier fluid is flowed against the droplet motion propelled by electrowetting to facilitate rapid removal of the gasses departing the droplet.

Disclosed are a water electrolysis system and a control method thereof. The water electrolysis system includes: i) a water electrolysis stack including active electrodes receiving an electrolyte and producing hydrogen and oxygen by electrolyzing the electrolyte; ii) a gas-liquid separation device receiving a product produced from the water electrolysis stack, separating the product into an electrolyte, oxygen, and hydrogen, and discharging the electrolyte, oxygen, and hydrogen; iii) a hydrogen sensor measuring a concentration of hydrogen in oxygen discharged from the gas-liquid separation device or a concentration of hydrogen in a circulating electrolyte; and iv) an electrolyte re-supplying module replenishing the electrolyte discharged from the gas-liquid separation device with water and then re-supplying the electrolyte to the water electrolysis stack, and selectively raising a temperature of the electrolyte on the basis of the concentration of hydrogen measured by the hydrogen sensor to remove gas in the electrolyte.

Devices, systems and methods are disclosed which relate to using containers with a multitude of nucleation sites covering a major portion of the inside wall of the container to enable rapid and nearly complete removal of soluble gases from fluid samples, including carbonated beverages and other carbonated fluid samples. A fluid sample is rapidly poured into the described container initiating a catastrophic release of the soluble gas from the sample.

A vapor recovery apparatus degasses oil and water produced by an oil well. The apparatus has a first vessel forming a column. Oil containing gas enters the bottom of the first vessel and flows up to a liquid outlet. Heat is applied to the rising oil, wherein the oil foams. Gas escapes into the upper end. The foam flows into a second column and along a roughened surface. The bubbles in the foam break apart, releasing the gas. The oil flows down the second column to an outlet. Water is introduced into a third vessel. The water releases gas therein, which gas mingles with the gas from the oil. The third vessel is located around the first and second vessels. A compressor may be used to withdraw the gas and provide hot compressed gas to heat the rising oil in the first column.

Systems and methods generate steam mixed with desired non-condensable gas concentrations using a direct steam generator. Injecting the steam into a reservoir may facilitate recovering hydrocarbons from the reservoir. Cooling an output of the direct steam generator produces water condensate, which is then separated from the non-condensable gas, such as carbon dioxide. Reducing pressure of the condensate subsequently heated by cross-exchange with effluent of the direct steam generator regenerates the steam with the carbon dioxide removed for the injection.

Systems and methods for separation of hydrocarbon containing fluids are provided. More particularly, the disclosure is relevant to separating fluids having a gas phase, a hydrocarbon liquid phase, and an aqueous liquid phase using indirect heating. In general, the system uses a first gas separation followed by pressure reduction and then a second gas separation. Indirect follows the second gas separation and then three-phase separation.

Inlet and outlet connections of a well manifold connect to integrated piping of a unitary vessel on a skid. The unitary vessel defines an interior separated into two chambers by a barrier. One chamber has a test inlet for well testing operation, and the other chamber has a production inlet for production operation. Each of the chambers is in communication with a gas outlet for gas, a water outlet for water, and a condensate outlet for condensate. Each of the chambers has a weir plate disposed in the chamber and separating the water outlet on a waterside of the weir plate from the condensate outlet on a condensate-side of the weir plate adjacent the barrier. During use, the second chamber can be isolated so well testing operation can be performed using the first chamber. Also, the first chamber can be isolated so production operation can be performed using the second chamber.

Apparatus and methods for degassing and analyzing drilling fluid discharged from a wellbore at an oil and gas wellsite. The apparatus may be a drilling fluid analysis system having a gas analyzer, a fluid analyzer, and a degasser operable to release and separate mud gas entrained in the drilling fluid. The degasser may include a gas-liquid separator having a separator inlet configured to receive the drilling fluid containing the entrained mud gas, a first separator outlet for discharging the mud gas fluidly connected with the gas analyzer, and a second separator outlet for discharging degassed drilling fluid fluidly connected with the fluid analyzer.

Embodiments of the present invention are generally related to a system and method to remove hydrogen sulfide from sour water and sour oil. Particularly, hydrogen sulfide is removed from sour water and sour oil without the need for special chemicals, such as catalyst chemicals, scavenger chemicals, hydrocarbon sources, or a large-scale facility. The system and method in the present invention is particularly useful in exploratory oil and gas fields, where large facilities to remove hydrogen sulfide may be inaccessible. The present invention addresses the need for safe and cost-effective transport of the deadly neurotoxin. Particular embodiments involve a system and method that can be executed both on a small and large scale to sweeten sour water and sour oil.

The present invention provides a heat exchange device featuring gas-liquid separation, comprising an evaporator unit and a condenser unit. The condenser unit comprises a central main guide tube, a plurality of condensation tubes connected to the two lateral sides of the central main guide tube, and a heat dissipation fin assembly provided on a periphery of each condensation tube. The central main guide tube comprises a gaseous-phase confluence chamber and a liquid-phase confluence chamber. The gaseous-phase confluence chamber is provided in an upper portion of the central main guide tube and communicates with the gas outlet through a gaseous-phase connection tube, and the liquid-phase confluence chamber is provided in a lower portion of the central main guide tube and communicates with the evaporation chamber through a liquid-phase connection tube. Each condensation tube comprises a first communicating section in communication with the gaseous-phase confluence chamber, a bent section bent downward from the first communicating section, and a second communicating section connecting the bent section to the liquid-phase confluence chamber.