Determining fluid properties from fluid analyzer

• US 6,956,204 B2
• Filed: 03/27/2003
• Issued: 10/18/2005
• Est. Priority Date: 03/27/2003
• Status: Expired due to Term

• Current Assignee: Schlumberger Oilfield Services (Schlumberger NV)
• Original Assignee: Schlumberger Technology Corporation (Schlumberger NV)
• Inventors: Hageman, Peter S., Elshahawi, Hani M., Mullins, Oliver C., Fujisawa, Go, Dong, Chengli, Kurkjian, Andrew L., Betancourt, Soraya S., Terabayashi, Toru, Pop, Julian
• Primary Examiner(s): Barlow, John
• Assistant Examiner(s): Taylor, Victor J.
• Application Number:
  US10/249,274
• Publication Number:
  US 20040193375A1
• Time in Patent Office: 936 Days
• Field of Search: 702/13, 702/152.22, 702/152.18, 702/152.29, 250/256, 250/269.1, 250/255, 250/326, 731/522.6, 731/522.2, 731/521.8, 731/522.9, 356/436
• US Class Current: 250/256
• CPC Class Codes: E21B 47/113 using electrical indications; using light radiations
• CPC Class Codes: G01N 21/3504 for analysing gases, e.g. multi-gas analysis
• CPC Class Codes: G01N 21/3577 for analysing liquids, e.g. polluted water
• CPC Class Codes: G01N 21/359 using near infrared light
• CPC Class Codes: G01N 33/2823 raw oil, drilling fluid or polyphasic mixtures hydrocarbon content of earth materials G01N33/241; prospecting G01V; drilling per se E21B

Abstract

A method for determining properties of a formation fluid including obtaining data related to an optical density at a methane peak and an optical density at an oil peak for a fluid sample at a plurality of times, calculating an apparent gas-oil-ratio of the sample fluid from the optical density of the fluid sample at the methane peak to the optical density of the fluid sample at the oil peak at each of the plurality of times based on the data, selecting a power function of a sampling parameter for a buildup of the apparent gas-oil-ratio, calculating an exponential constant of the power function based on the data, and determining at least one selected from the group consisting of a contamination free gas-oil-ratio and a percent contamination.

Claims

1. A method for determining properties of a formation fluid, comprising:

obtaining data related to an optical density at a methane peak and an optical density at an oil peak for a fluid sample at a plurality of times;

calculating an apparent gas-oil-ratio of the fluid sample from the optical density of the fluid sample at the methane peak and the optical density of the fluid sample at the oil peak at more than one of the plurality of times;

selecting a power function of a sampling parameter for a buildup of the apparent gas-oil-ratio;

calculating an exponential constant of the power function based on the data; and

determining at least one selected from the group consisting of a contamination free gas-oil-ratio and a percent contamination.

2. The method of claim 1, wherein the sampling parameter is one selected from the group consisting of elapsed time, pumping time, and pumpout volume.

3. The method of claim 1, wherein determining the exponential constant comprises selecting a fitting interval for a plot of logarithm of a derivative of the gas-oil-ratio with respect to a natural log of the sampling parameter versus the natural log of the sampling parameter and determining the slope of the plot over the fitting interval.

4. The method of claim 3, wherein the fitting interval is automatically selected.

5. The method of claim 1, wherein the sampling parameter is one selected from the group consisting of a pumping time and an elapsed time, and further comprising determining a time when the fluid sample will comprise an acceptably low volume percent contamination.

6. The method of claim 1, wherein the sampling parameter is a pumpout volume and further comprising determining a pumpout volume where the fluid sample will comprise an acceptably low volume percent contamination.

7. The method of claim 1, wherein determining at least one selected from the group consisting of the contamination free gas-oil-ratio and the volume percent contamination comprises determining the contamination free gas-oil-ratio and further comprising extrapolating the gas-oil-ratio versus the sampling parameter to the power of the exponential constant to a point where the sampling parameter to the power of the exponential constant equals zero.

8. A method for determining properties of a formation fluid, comprising:

obtaining data related to an optical density at a methane peak and at an optical density at an oil peak for a fluid sample at a plurality of times;

calculating an apparent gas-oil-ratio of the sample fluid at the plurality of times based on the data;

selecting an exponential function of a sampling parameter for a buildup of the apparent gas-oil-ratio; and

linearly extrapolating the gas-oil-ratio to a point where a derivative of the exponential function with respect to the sampling parameter is zero.

9. The method of claim 8, wherein the sampling parameter is one selected from the group consisting of elapsed time, pumping time, and pumpout volume.

10. The method of claim 8, further comprising determining a percent contamination of the fluid sample.

11. The method of claim 8, wherein the sampling parameter is one selected from the group consisting of a pumping time and an elapsed time, and further comprising determining a time when the fluid sample will comprise an acceptably low volume percent contamination.

12. The method of claim 8, wherein the sampling parameter is a pumpout volume and further comprising determining a pumpout volume where the fluid sample will comprise an acceptably low volume percent contamination.

13. A method for determining a gas-oil-ratio of a fluid sample, comprising:

obtaining data related to a methane mass component, a non-methane gaseous hydrocarbon mass component, a liquid phase hydrocarbon mass component, and a carbon dioxide mass component at a plurality of times; and

determining the gas-oil-ratio from the ratio of the methane mass component, the non-methane gaseous hydrocarbon mass component, and the carbon dioxide mass component to the liquid phase hydrocarbon mass component.

14. The method of claim 13, wherein the determining the gas-oil-ratio comprises using a function of the methane mass concentration, the non-methane gaseous hydrocarbon mass component, the liquid phase hydrocarbon mass component, and the carbon dioxide mass component.

15. The method of claim 13, wherein the function is based on assumptions about formation fluid components.

16. The method of claim 15, wherein the assumptions comprise:

that the fluid sample may be approximated as a combination of a methane molecule group, a non-methane gaseous hydrocarbon molecule group, a liquid phase hydrocarbon molecule group, and a carbon dioxide molecule group;

that the methane molecule group, the non-methane gaseous hydrocarbon molecule group, and the carbon dioxide molecule group are in the gaseous phase at a standard condition;

that the liquid phase hydrocarbon molecule group is entirely in the liquid phase at the standard condition;

that a mass distribution between the ethane molecule, propane molecule, butane molecule and pentane molecule is about 4 to 3 to 2 to 1, respectively;

that a density of the liquid phase hydrocarbon molecule group is about 0.75 g/cm³; and

that the methane molecule group, the non-methane gaseous hydrocarbon molecule group, and the carbon dioxide molecule group obey an Ideal Gas Law.

17. The method of claim 15, wherein the assumptions comprise:

that a methane molecule group, a non-methane gaseous hydrocarbon molecule group, and a carbon dioxide molecule group are entirely in the gaseous phase after the fluid is flashed at the standard condition;

that after the fluid is flashed, the liquid phase contains 4 mol% hexane, 5 mol% septan;

7 mol % octane, and 8 mol % nonane;

that in the gaseous phase, the vapors of hezane, septane, octane, and nonane are in equilibrium with the liquid phase; and

that the density of the liquid phase is 0.8 g/cm³.

18. A method for determining properties of a formation fluid, comprising:

obtaining data related to a mass concentration of methane and a mass concentration of liquid phase hydrocarbons for a fluid sample at a plurality of times;

calculating an apparent methane mass concentration and an apparent liquid phase hydrocarbon mass concentration of the fluid sample at each of the plurality of times;

selecting a methane power function of a sampling parameter for a buildup of the apparent methane mass concentration;

selecting a liquid phase power function of the sampling parameter for a buildup of the apparent liquid phase hydrocarbon mass concentration;

determining an exponential constant of the methane power function based on the data;

determining an exponential constant of the liquid phase power function based on the data; and

determining a percent contamination.

19. The method of claim 18, wherein the determining the exponential constant of the methane-power function based on the data comprises selecting the exponential constant of the methane power function to be between about 0.1 and 20, and wherein the determining the exponential constant of the liquid phase power function based on the data comprises selecting the exponential constant of the liquid phase power function to be between about 0.1 and 2.0.

20. The method of claim 18, wherein the determining the exponential constant of the methane power function based on the data comprises selecting the exponential constant of the methane power function to be about 0.5, and wherein determining the exponential constant of the liquid phase power function based on the data comprises selecting the exponential constant of the liquid phase power function to be about 0.5.

21. The method of claim 18, wherein the determining the exponential constant of the methane power function based on the data comprises selecting the exponential constant of the methane power function to be about ⅓

for a formation with a shallow invasion and ⅔

for a formation with a deep invasion, and wherein the detemiining the exponential constant of the liquid phase power function based on the data comprises selecting the exponential constant of the liquid phase power function to be about ⅓

for a formation with a shallow invasion and ⅔

for a formation with a deep invasion.

22. The method of claim 18, wherein the sampling parameter is one selected from the group consisting of elapsed time, pumping time, and pumpout volume.

23. The method of claim 18, wherein the determining the exponential constant of the methane power function comprises selecting a fitting interval for a methane plot of a natural log of a derivative of the methane mass concentration with respect to a natural log of the sampling parameter versus the natural log of the sampling parameter and determining a slop of the methane plot over the fitting interval, and wherein the determining the exponential constant of the liquid phase power function comprises selecting a fitting interval for a liquid phase plot of a natural log of a derivative of the liquid phase hydrocarbon mass concentration with respect to the natural log of the sampling parameter versus the natural log of the sampling parameter and determining a slope of the liquid phase plot over the fitting interval.

24. The method of claim 23, wherein the fitting interval for the methane plot is automatically selected and the fitting interval for the liquid phase plot is automatically selected.

25. The method of claim 18, wherein the sampling parameter is one selected from the group consisting of a pumping time and an elapsed time, and further comprising determining a time when the fluid sample will contain less than a predetermined level of contamination.

26. The method of claim 18, wherein the sampling parameter is a pumpout volume and further comprising determining a pumpout volume where the fluid sample will comprise an acceptably low volume percent contamination.

27. A method for determining properties of a formation fluid, comprising:

obtaining data related to a mass concentration of methane and a mass concentration of liquid phase hydrocarbons for a fluid sample at a plurality of times;

calculating an apparent methane mass concentration and an apparent liquid phase hydrocarbon mass concentration of the fluid sample at each of the plurality of times;

selecting a methane exponential function of a sampling parameter for a buildup of the apparent methane mass concentration;

selecting a liquid phase exponential function of the sampling parameter for a buildup of the apparent liquid phase hydrocarbon mass concentration; and

determining a percent contamination from the data.

28. The method of claim 27, wherein the sampling parameter is one selected from the group consisting of elapsed time, pumping time and pumpout volume.

29. The method of claim 27, wherein the sampling parameter is one selected from the group consisting of a pumping time and an elapsed time, and further comprising determining a time when the fluid sample will contain less than a predetermined level of contamination.

30. The method of claim 27, wherein the sampling parameter is a pumpout volume and further comprising determining a pumpout volume where the fluid sample will contain less than a predetermined level of contamination.