A water content sensor is positioned within a flowline downstream of a well-choke. The water content sensor is configured to determine a water content percentage of a production fluid flowing through the flowline. A temperature sensor is positioned downstream of the well-choke. The temperature sensor is configured to determine a temperature of the production fluid flowing through the flowline. A heating jacket surroundings at least a portion of the flowline. The heating-jacket is configured to transfer heat into the flowline. A controller is configured to receive a signal from each of the water content sensor and the temperature sensor, and control the heating jacket in response to a signal from each of the water content sensor and the temperature sensor.

A water content sensor is positioned within a flowline downstream of a well-choke. The water content sensor is configured to determine a water content percentage of a production fluid flowing through the flowline. A temperature sensor is positioned downstream of the well-choke. The temperature sensor is configured to determine a temperature of the production fluid flowing through the flowline. A heating jacket surroundings at least a portion of the flowline. The heating-jacket is configured to transfer heat into the flowline. A controller is configured to receive a signal from each of the water content sensor and the temperature sensor, and control the heating jacket in response to a signal from each of the water content sensor and the temperature sensor.

A method for using the time derivative of distributed temperature sensing (DTS) data obtained during hydraulic fracturing to identify fluid activities not as evident in conventional DTS date inside or near the wellbore during the hydraulic fracturing process comprises providing a fiber optic based distributed temperature sensing measurement system through a production region; gathering the temperatures through the production region as a function of the depth in the subsurface well and as a function of the elapsed time; calculating from the gathered data the time derivative of the temperature changes as a function of depth in the subsurface well and of the elapsed time; and displaying the time derivative data for analysis of the fluid activities inside or near the wellbore during the hydraulic fracturing process to identify fluid activities inside or near the wellbore.

A well system includes a target wellbore that penetrates a subterranean formation and a relief wellbore drilled toward the target wellbore and a target intercept location where a fluid flows into the target wellbore from the subterranean formation. A bottom hole assembly is coupled to a drill string extended into the relief wellbore and includes a fiber optic ranging assembly having one or more fiber optic sensors positioned on a tubular member. The fiber optic sensors measure at least one of acoustic energy and thermal energy emitted by the fluid as it flows into the target wellbore. A computer system is communicably coupled to the one or more fiber optic sensors to process measurements of the fluid obtained by the one or more fiber optic sensors.

A well system includes a target wellbore that penetrates a subterranean formation and a relief wellbore drilled toward the target wellbore and a target intercept location where a fluid flows into the target wellbore from the subterranean formation. A bottom hole assembly is coupled to a drill string extended into the relief wellbore and includes a fiber optic ranging assembly having one or more fiber optic sensors positioned on a tubular member. The fiber optic sensors measure at least one of acoustic energy and thermal energy emitted by the fluid as it flows into the target wellbore. A computer system is communicably coupled to the one or more fiber optic sensors to process measurements of the fluid obtained by the one or more fiber optic sensors.

A method for determining a flow distribution of a wellbore during a wellbore treatment comprises disposing an optical fiber into a wellbore, performing a wellbore treatment in the wellbore with the fiber optic in place by flowing a well treatment fluid from the surface and wellbore and into the formation, taking distributed temperature measurements at a time interval with the fiber optic cable during the wellbore treatment operation, and calculating a flow distribution of the wellbore while performing the wellbore treatment.

Given a number of temperature measurements, such as from a Distributed Temperature Sensing System (DTS), at various depths in a wellbore, a derivative of temperature with respect to depth can be calculated. A fluid boundary can then be identified where the depths below the boundary corresponds to the presence of fluid and a low fluctuation regime in the derivative of temperature with respect to depth, and the depths above the boundary correspond to the absence of fluid and a high fluctuation regime in the derivative of temperature with respect to depth.

A method for hydrocarbon production includes receiving data from a sensor associated with hydrocarbon production equipment, the hydrocarbon production equipment configured to extract hydrocarbons from a site, determining, based on the sensor data and a model associated with extracted hydrocarbons, multiphase properties of the extracted hydrocarbons, determining that a portion of the multiphase properties exceeds a threshold value, and controlling the hydrocarbon production equipment based on the multiphase properties responsive to determining that the portion of the multiphase properties exceeds the threshold value.

A water content sensor is positioned within a flowline downstream of a well-choke. The water content sensor is configured to determine a water content percentage of a production fluid flowing through the flowline. A temperature sensor is positioned downstream of the well-choke. The temperature sensor is configured to determine a temperature of the production fluid flowing through the flowline. A heating jacket surroundings at least a portion of the flowline. The heating-jacket is configured to transfer heat into the flowline. A controller is configured to receive a signal from each of the water content sensor and the temperature sensor, and control the heating jacket in response to a signal from each of the water content sensor and the temperature sensor.

A water content sensor is positioned within a flowline downstream of a well-choke. The water content sensor is configured to determine a water content percentage of a production fluid flowing through the flowline. A temperature sensor is positioned downstream of the well-choke. The temperature sensor is configured to determine a temperature of the production fluid flowing through the flowline. A heating jacket surroundings at least a portion of the flowline. The heating-jacket is configured to transfer heat into the flowline. A controller is configured to receive a signal from each of the water content sensor and the temperature sensor, and control the heating jacket in response to a signal from each of the water content sensor and the temperature sensor.