Flow rate optimizer

1. A method of hydrocarbon monitoring, comprising:

receiving downhole measurements of a flowing fluid from a flowmeter;

determining a standard phase fraction and a speed of sound (SoS) of a first phase of the flowing fluid based on the downhole measurements from the flowmeter;

receiving surface measurements of the flowing fluid;

determining a surface phase fraction of the flowing fluid based on the surface measurements;

comparing the standard phase fraction to the surface phase fraction to generate a comparison;

adjusting, based on the comparison being greater than a predetermined threshold and using the surface measurements as a reference, the SoS of the first phase until a target value is achieved, to generate an adjusted SoS of the first phase; and

receiving additional downhole measurements of the flowing fluid from the flowmeter, wherein the flowmeter is operating using the adjusted SoS of the first phase for the additional downhole measurements.

2. The method of claim 1 , further comprising determining at least one of an updated in-situ phase fraction, an updated standard phase fraction, or updated phase flow rates of the flowing fluid, based on the additional downhole measurements.

3. The method of claim 1 , wherein the standard phase fraction comprises a water-in-liquid ratio (WLR) at standard conditions.

4. The method of claim 1 , wherein the surface measurements of the flowing fluid are received from at least one of a wellhead or a separator.

5. The method of claim 1 , wherein the target value comprises a target mixture SoS.

6. The method of claim 5 , wherein using the surface measurements as the reference to adjust the SoS of the first phase comprises:

calculating a target mixture density based on the surface phase fraction;

calculating the target mixture SoS based on the target mixture density; and

changing the SoS of the first phase until a resulting mixture SoS obtained from the Wood's equation is within a predetermined deviation from the target mixture SoS, while leaving a SoS of a second phase constant.

7. The method of claim 6 , wherein the SoS of the first phase is a SoS of oil and wherein the SoS of the second phase is a SoS of water.

8. The method of claim 6 , wherein the SoS of the first phase is a SoS of gases in the fluid, wherein the SoS of the second phase is a SoS of liquids in the fluid, and wherein the phase fraction comprises a liquid volume fraction (HL) of the fluid.

9. The method of claim 6 , wherein calculating the target mixture density comprises:

predicting an in-situ phase fraction based on the surface phase fraction, the standard phase fraction, a downhole pressure measurement, a downhole temperature measurement, a surface pressure measurement, a surface temperature measurement, a standard pressure, and a standard temperature; and

calculating the target mixture density based on the in-situ phase fraction.

10. The method of claim 6 , wherein calculating the target mixture SoS is based on the Korteweg-Lamb equation.

11. The method of claim 1 , further comprising updating a parameter file for the flowmeter with the adjusted SoS of the first phase.

12. The method of claim 11 , wherein the adjusted SoS of the first phase is at a measured downhole temperature and a measured downhole pressure and wherein the updating comprises:

extrapolating additional adjusted speeds of sound of the first phase for temperatures other than the measured downhole temperature and for pressures other than the measured downhole pressure; and

writing the adjusted SoS of the first phase at the measured downhole temperature and pressure and the extrapolated additional adjusted speeds of sound of the first phase to the parameter file for the flowmeter.

13. The method of claim 1 , further comprising applying a conversion factor to at least one of the standard phase fraction or the surface phase fraction before the comparing.

14. The method of claim 1 , wherein the flowmeter comprises an optical flowmeter.

15. The method of claim 1 , further comprising:

determining an updated standard phase fraction of the flowing fluid based on the additional downhole measurements;

receiving additional surface measurements of the flowing fluid;

determining an updated surface phase fraction of the flowing fluid based on the additional surface measurements;

comparing the updated standard phase fraction to the updated surface phase fraction to generate a comparison of the updated standard and surface phase fractions;

altering, based on the comparison of the updated standard and surface phase fractions being greater than the predetermined threshold and using the additional surface measurements as an updated reference, the adjusted SoS of the first phase until an updated target value is achieved, to generate an altered SoS of the first phase; and

receiving further downhole measurements of the flowing fluid from the flowmeter, wherein the flowmeter is operating using the altered SoS of the first phase for the further downhole measurements.

16. The method of claim 15 , further comprising calculating adjustments to past downhole measurements based on the altered SoS of the first phase.

17. The method of claim 1 , further comprising calculating adjustments to past downhole measurements based on the adjusted SoS of the first phase.

18. A processing system for hydrocarbon monitoring, the processing system being configured to:

receive downhole measurements of a flowing fluid from a flowmeter;

determine a standard phase fraction and a speed of sound (SoS) of a first phase of the flowing fluid based on the downhole measurements from the flowmeter;

receive surface measurements of the flowing fluid;

determine a surface phase fraction of the flowing fluid based on the surface measurements;

compare the standard phase fraction to the surface phase fraction to generate a comparison;

adjust, based on the comparison being greater than a predetermined threshold and using the surface measurements as a reference, the SoS of the first phase until a target value is achieved, to generate an adjusted SoS of the first phase; and

receive additional downhole measurements of the flowing fluid from the flowmeter, the flowmeter being configured to operate using the adjusted SoS of the first phase for the additional downhole measurements.

19. The processing system of claim 18 , wherein the processing system is further configured to determine at least one of an updated in-situ phase fraction, an updated standard phase fraction, or updated phase flow rates of the flowing fluid, based on the additional downhole measurements.

20. The processing system of claim 18 , wherein the standard phase fraction comprises a water-in-liquid ratio (WLR) at standard conditions.

21. The processing system of claim 18 , wherein the processing system is configured to receive the surface measurements of the flowing fluid from at least one of a wellhead or a separator.

22. The processing system of claim 18 , wherein the target value comprises a target mixture SoS.

23. The processing system of claim 22 , wherein the processing system is configured to use the surface measurements as the reference to adjust the SoS of the first phase by:

calculating a target mixture density based on the surface phase fraction;

calculating the target mixture SoS based on the target mixture density; and

changing the SoS of the first phase until a resulting mixture SoS obtained from the Wood's equation is within a predetermined deviation from the target mixture SoS, while leaving a SoS of a second phase constant.

24. The processing system of claim 18 , wherein the processing system is further configured to update a parameter file for the flowmeter with the adjusted SoS of the first phase.

25. The processing system of claim 18 , wherein the processing system is further configured to apply a conversion factor to at least one of the standard phase fraction or the surface phase fraction before the comparing.

26. The processing system of claim 18 , wherein the flowmeter comprises an optical flowmeter.

27. The processing system of claim 18 , wherein the processing system is further configured to:

determine an updated standard phase fraction of the flowing fluid based on the additional downhole measurements;

receive additional surface measurements of the flowing fluid;

determine an updated surface phase fraction of the flowing fluid based on the additional surface measurements;

compare the updated standard phase fraction to the updated surface phase fraction to generate a comparison of the updated standard and surface phase fractions;

alter, based on the comparison of the updated standard and surface phase fractions being greater than the predetermined threshold and using the additional surface measurements as an updated reference, the adjusted SoS of the first phase until an updated target value is achieved, to generate an altered SoS of the first phase; and

receive further downhole measurements of the flowing fluid from the flowmeter, the flowmeter being configured to operate using the altered SoS of the first phase for the further downhole measurements.

28. The processing system of claim 27 , wherein the processing system is further configured to calculate adjustments to past downhole measurements based on the altered SoS of the first phase.

29. The processing system of claim 18 , wherein the processing system is further configured to calculate adjustments to past downhole measurements based on the adjusted SoS of the first phase.

30. A non-transitory computer-readable medium comprising instructions executable by a processing system to perform operations for hydrocarbon monitoring, the operations comprising:

receiving downhole measurements of a flowing fluid from a flowmeter;

determining a standard phase fraction and a speed of sound (SoS) of a phase of the flowing fluid based on the downhole measurements from the flowmeter;

receiving surface measurements of the flowing fluid;

determining a surface phase fraction of the flowing fluid based on the surface measurements;

comparing the standard phase fraction to the surface phase fraction to generate a comparison;

adjusting, based on the comparison being greater than a predetermined threshold and using the surface measurements as a reference, the SoS of the phase until a target value is achieved, to generate an adjusted SoS of the phase; and

receiving additional downhole measurements of the flowing fluid from the flowmeter, wherein the flowmeter is operating using the adjusted SoS of the phase for the additional downhole measurements.