Multi-phase fluid identification for subsurface sensor measurement

1. A method for measuring downhole fluid properties, comprising:

disposing a downhole fluid sampling tool into a wellbore wherein the downhole fluid sampling tool comprises:

at least one probe configured to fluidly connect the downhole fluid sampling tool to a formation in the wellbore; and

at least one passageway that passes through the at least one probe and into the downhole sampling tool;

drawing a wellbore fluid through the at least one probe and through the at least one passageway;

obtaining a first channel measurement of the wellbore fluid with at least one sensor that is fluidly coupled to the at least one passageway;

obtaining at least a second channel measurement from the at least one sensor, wherein the at least one sensor is an optical fluid sensor;

clustering channel data from a plurality of channel measurements comprising the first channel measurement and the at least second channel measurement, wherein the first channel and the at least second channel are active optical channel pair measuring the wellbore fluid simultaneously at different wavelength;

measuring a phase through a plurality of channels;

separating a plurality of phase signals based on the phase measured through the plurality of channels;

labeling the wellbore fluid based at least in part on the plurality of phase signals;

assigning the plurality of phase signals to specific phases of a multi-phase fluid; and

estimating a fluid property of the wellbore fluid.

2. The method of claim 1 , wherein the plurality of channels are positioned together.

3. The method of claim 1 , wherein the plurality of channels are synchronized.

4. The method of claim 1 , wherein the fluid property comprises compositional component concentrations comprising methane, ethane, propane, butane, pentane, or combinations thereof.

5. The method of claim 1 , wherein the fluid property comprises organic liquid components comprising a hexane plus fraction, saturates fraction, aromatics fraction, resins fraction, asphaltenes fraction, or combinations thereof.

6. The method of claim 1 , wherein the fluid property is a physical property selected from the group consisting of compressibility, density, thermal conductivity, heat capacity, viscosity, bubble point, gas to oil ration, phase envelope for gas-liquid, phase envelope for solid-liquid, or combinations thereof.

7. The method of claim 1 , further comprising identifying pure phase channel observations versus mixed phased channel observations for each of the plurality of channels.

8. The method of claim 1 , further comprising identifying the phases of a dominating fluid for each of the plurality of channels.

9. The method of claim 8 , wherein identifying the phases of the dominating fluid comprises determining a current water ratio.

10. The method of claim 9 , wherein the dominating fluid is hydrocarbon when the current water ratio is less than a threshold.

11. The method of claim 9 , wherein the dominating fluid is water when the current water ratio is not less than a threshold.

12. The method of claim 8 , wherein labeling the fluid further comprises labeling a first cluster group, wherein the first cluster group is the cluster group that has more samples with the dominating fluid.

13. The method of claim 12 , further comprising labeling a second cluster group with another fluid type, wherein the second cluster group is the cluster group that has the least number of samples with the dominating fluid.

14. A system comprising:

a downhole fluid sampling tool comprising:

at least one probe configured to fluidly connect the downhole fluid sampling tool to a formation in the wellbore;

at least one passageway that passes through the at least one probe and into the downhole sampling tool; and

at least one sensor that is fluidly couple to the at least one passageway and configured to take a first channel measurement and at least a second channel measurement of a wellbore fluid that is drawn from the formation and through the at least one passageway, wherein the at least one sensor is an optical fluid sensor; and

an information handling system configured to:

cluster channel data from a plurality of channel measurements comprising the first channel measurement and the at least second channel measurement, wherein the first channel and the at least second channel are active optical channel pair measuring the wellbore fluid simultaneously at different wavelength;

measure a phase through a plurality of channels;

separate a plurality of phase signals based on the phase measured through the plurality of channels;

label the wellbore fluid based at least in part on the plurality of phase signals;

assign the plurality of phase signals to specific phases of a multi-phase fluid; and

estimate a fluid property of the wellbore fluid.

15. The system of claim 14 , wherein the plurality of channels are positioned together.

16. The system of claim 14 , wherein the plurality of channels are synchronized.

17. A method for measuring downhole fluid properties, comprising:

disposing a downhole fluid sampling tool into a wellbore wherein the downhole fluid sampling tool comprises:

at least one probe configured to fluidly connect the downhole fluid sampling tool to a formation in the wellbore; and

at least one passageway that passes through the at least one probe and into the downhole sampling tool;

drawing a wellbore fluid through the at least one probe and through the at least one passageway;

obtaining a first channel measurement of the wellbore fluid with at least one sensor that is fluidly coupled to the at least one passageway;

obtaining at least a second channel measurement from the at least one sensor, wherein the at least one sensor is an optical fluid sensor;

clustering channel data from a plurality of channel measurements comprising the first channel measurement and the at least second channel measurement, wherein the first channel and the at least second channel are active optical channel pair measuring the wellbore fluid simultaneously;

measuring a phase through a plurality of channels;

separating a plurality of phase signals based on the phase measured through the plurality of channels;

labeling the wellbore fluid based at least in part on the plurality of phase signals;

assigning the plurality of phase signals to specific phases of a multi-phase fluid; and

estimating a fluid property of the wellbore fluid.