Systems and methods of the present disclosure generally relate to correcting isotope ratio calculations during wellbore operation. A method for correcting isotope ratios during a wellbore operation, comprising: receiving a flow-in fluid sample from a wellbore; receiving a flow-out fluid sample from the wellbore; passing each sample to an analytical instrument operable to determine isotopes in each fluid sample; outputting a signal intensity or signa area: assigning a depth to the signal intensity or the signal area; and determining a corrected isotope ratio by subtracting a signal for the flow-in fluid sample from a signal for the flow-out fluid sample.

The subject disclosure provides for a method of optical sensor calibration implemented with neural networks through machine learning to make real-time optical fluid answer product prediction adapt to optical signal variation of synthetic and actual sensor inputs integrated from multiple sources. Downhole real-time fluid analysis can be performed by monitoring the quality of the prediction with each type of input and determining which type of input generalizes better. The processor can bypass the less robust routine and deploy the more robust routine for remainder of the data prediction. Operational sensor data can be incorporated from a particular optical tool over multiple field jobs into an updated calibration when target fluid sample compositions and properties become available. Reconstructed fluid models adapted to prior field job data, in the same geological or geographical area, can maximize the likelihood of quality prediction on future jobs and optimize regional formation sampling and testing applications.

A method and system for determining dynamic steady-state flow and chemistry of groundwater within a long-screened test well, includes (i) drilling a pilot hole through an aquifer; (ii) installing a test well within the pilot hole, including a well screen that is at least 40 feet in length; (iii) positioning a pump within the test well to move the groundwater within the test well; (iv) positioning a packer assembly within the test well to selectively provide a seal between the test well and the pilot hole; and (v) performing downhole testing at a plurality of different depths within the test well with miniaturized technologies that are equal to or less than 1.5 inches in diameter to determine a dynamic steady-state flow and chemistry profile of the groundwater within the test well. The pump is used at a first depth and then is moved to a second depth within the test well to perform stacked dynamic steady-state flow and chemistry profiles. The miniaturized technologies include a tracer injection system that determines downhole velocity and flow measurements of the groundwater within the test well, and a groundwater sampling system that selectively removes groundwater samples from the test well.

Various embodiments provide methods and systems for providing sustainable and environmentally friendly fluid lighteners for use in downhole wells. The sustainable and environmentally friendly fluid lighteners may include one or more viscosifiers, one or more aphron generators, and a location-specific non-emulsifying or de-emulsifying surfactant. Various embodiments provide methods and systems for providing continuity of chemistry in downhole wells.

Apparatus and methods for obtaining a data response of a fluid as a function of pressure of the fluid, and estimating a dew point pressure of the fluid by detecting an inflection pressure, a downward curve pressure, a characteristic change pressure, and an intersection pressure of the function representative of the data response. The estimated dew point pressure of the fluid based on at least one of the inflection pressure, the downward curve pressure, the characteristic change pressure, and the intersection pressure.

Systems and methods of the present disclosure generally relate to correcting isotope ratio calculations during wellbore operation. A method for correcting isotope ratios during a wellbore operation, comprising receiving a flow-in fluid sample from a wellbore; receiving a flow-out fluid sample from the wellbore; passing each sample to an analytical instrument operable to determine isotopes in each fluid sample; outputting a signal intensity or signal area; assigning a depth to the signal intensity or the signal area; and determining a corrected isotope ratio by subtracting a signal for the flow-in fluid sample from a signal for the flow-out fluid sample.

An assembly and a method for filtering a particulate from a wellbore fluid flow entering a downhole shut-in device in a wellbore are described. The downhole shut-in device includes a valve body with an inlet. An inner sleeve is coupled to an inner surface of the valve body and moves between a closed position and an open position to control a fluid flow from the wellbore through the inlet of the valve body. The downhole shut-in device includes a screen surrounding an outer surface of the valve body to filter the particulate from the fluid flow through the inlet of the valve body. Some devices also include a strainer tool with a cylindrical housing and an internal strainer. The method includes identifying a production fluid flow containing particulates of a size and quantity to be filtered from entering the downhole shut-in device.

The invention relates to a fluid sampling device comprising a sample chamber (01) including a lower piston (05), an upper piston (02) and an intermediate piston (28). Intermediate piston (28) is moved so as to guarantee a substantially constant volume for chamber (01) when closing the chamber.

The present disclosure relates to methods and apparatus for determining a viscosity-pressure profile of downhole fluid by measuring the viscosity at several different pressures during a sampling operation. According to certain embodiments, the viscosity may be measured at different times during a sampling operation and used to generate the viscosity-pressure profile. For example, the viscosity may be measured at the beginning of pumping, during filling of a sample chamber, during a pressure-build up period, and while retracting the probe. The measured viscosities may then be employed to determine a profile that represents the change in viscosity that occurs with pressure.

Methods and systems for predicting oil production from a reservoir are configured for obtaining production data from a hydrocarbon reservoir, the production data comprising data representing a fractional oil flow; determining, based on the production data, a relationship between the fractional oil flow and cumulative liquid production; identifying, based on the relationship between the fractional oil flow and cumulative liquid production, a post-water breakthrough point; estimating a value for a group parameter at a reference point of the relationship occurring after the post-water breakthrough point; and based on the value of the group parameter, generating a prediction of a future fractional oil flow and a future rate of production of oil from the hydrocarbon reservoir.