A method is provided. Sensor data regarding a wellbore is received from at least one of a distributed fiber optic sensing line positioned along the wellbore and a plurality of subsurface and surface sensors. Flow models are generated based on the sensor data to optimize production flow. Flow profiles are generated based on the flow models and the sensor data to adjust at least one gas lift valve.

A method of detecting one or more events comprises determining a plurality of temperature features from a temperature sensing signal, using the plurality of temperature features in an event detection model, and determining the presence or absence of the one or more events at one or more locations based on an output from the event detection model.

A method of detecting one or more events comprises determining a plurality of temperature features from a temperature sensing signal, using the plurality of temperature features in an event detection model, and determining the presence or absence of the one or more events at one or more locations based on an output from the event detection model.

Tools and methods are used to determine the oil, water, and solids volume fractions in a drilling fluid at the rig site. The volume fractions can be determined in-line with returned drilling fluid by using an NMR magnet and a flow line or sample chamber that receives a fluid sample and loads it into the NMR magnet. Using an RF probe, spectrometer, and computing device, data processing and interpretation of NMR data from the spectrometer is performed, while also raising a flag when iron contamination exceeds a predefined threshold.

A system can receive data that can indicate a flow rate with respect to perforations in a reference wellbore. The data can be received from a fiber optic cable in the reference wellbore in a geographic area of interest. The system can determine a uniformity index, which can indicate a uniformity of flow with respect to the perforations, based on the data. The system can generate a pressure-based model by training a model using the uniformity index for applying the pressure-based model to a target wellbore in the geographic area of interest to determine controls to rate and proppant with respect to the target wellbore.

A system can receive data that can indicate a flow rate with respect to perforations in a reference wellbore. The data can be received from a fiber optic cable in the reference wellbore in a geographic area of interest. The system can determine a uniformity index, which can indicate a uniformity of flow with respect to the perforations, based on the data. The system can generate a pressure-based model by training a model using the uniformity index for applying the pressure-based model to a target wellbore in the geographic area of interest to determine controls to rate and proppant with respect to the target wellbore.

A well bore logging tool for measuring a pore fluid property of a hydrocarbon reservoir that may include, a tool housing, a vessel containing a tracer, a launcher attached to the vessel that may be configured to inject a tracer into the hydrocarbon reservoir. The well bore logging too may further include a retrieval device configured to extract at least a portion of the tracer from the hydrocarbon reservoir. The well bore logging too may further include a storage canister may be configured to store a portion of the tracer extracted from the hydrocarbon reservoir, and a scanning device may be configured to read a value of at least one fluid saturation property detected by the tracer. The vessel, launcher, retrieval device, storage canister, and scanning device may be enclosed in a tool housing.

A production monitoring system includes a distributed acoustic sensing subsystem that includes a first optical fiber for a distributed acoustic sensing signal and a distributed temperature sensing subsystem that includes a second optical fiber for a distributed temperature sensing signal. The production monitoring system, also includes a cable positioned in a wellbore penetrating through one or more subterranean formations. The distributed acoustic sensing subsystem is communicatively coupled to the cable through the distributed temperature sensing subsystem. The cable includes one or more optical fibers used to obtain optical fiber measurements pertaining to the distributed acoustic sensing signal and the distributed temperature sensing signal. The optical fibers include a sensing fiber that is common between the distributed acoustic sensing subsystem and the distributed temperature sensing subsystem. The distributed acoustic sensing subsystem, receives at least a portion of the optical fiber measurements from the sensing fiber through the distributed temperature sensing subsystem.

These drawings Illustrate certain aspects of some of the embodiments of the present disclosure, and should not be used to limit or define the claims. FIG. 1 is a schematic diagram of an acrolein injection system and acrolein leak detection and alert system that may be used in accordance with certain embodiments of the present disclosure. FIG. 2 is another schematic diagram of an acrolein injection system and acrolein leak detection and alert: system that may be used in accordance with certain embodiments of the present disclosure. FIG. 3 is another schematic diagram of an acrolein injection system and acrolein leak detection and alert system that may be used in accordance with certain embodiments of the present disclosure. FIG. 4 is a diagram illustrating an example of a wellbore drilling assembly that may be used in accordance with certain embodiments of the present disclosure. While embodiments: of this disclosure have been depicted, such embodiments do not imply a limitation on the disclosure, and no such limitation should be inferred. The subject matter disclosed is capable of considerable modification, alteration, and equivalents in form: and function, as will occur to those skilled in the pertinent art and having the benefit of this disclosure. The depicted and described embodiments of this disclosure are examples only, and not exhaustive of the scope of the disclosure.

These drawings Illustrate certain aspects of some of the embodiments of the present disclosure, and should not be used to limit or define the claims. FIG. 1 is a schematic diagram of an acrolein injection system and acrolein leak detection and alert system that may be used in accordance with certain embodiments of the present disclosure. FIG. 2 is another schematic diagram of an acrolein injection system and acrolein leak detection and alert: system that may be used in accordance with certain embodiments of the present disclosure. FIG. 3 is another schematic diagram of an acrolein injection system and acrolein leak detection and alert system that may be used in accordance with certain embodiments of the present disclosure. FIG. 4 is a diagram illustrating an example of a wellbore drilling assembly that may be used in accordance with certain embodiments of the present disclosure. While embodiments: of this disclosure have been depicted, such embodiments do not imply a limitation on the disclosure, and no such limitation should be inferred. The subject matter disclosed is capable of considerable modification, alteration, and equivalents in form: and function, as will occur to those skilled in the pertinent art and having the benefit of this disclosure. The depicted and described embodiments of this disclosure are examples only, and not exhaustive of the scope of the disclosure.