Downhole formation fluid contamination assessment

Patent metadata

Field	Value
Publication number	US-9334727-B2
Application number	US-201113995881-A
Country	US
Kind code	B2
Filing date	Jan 6, 2011
Priority date	Jan 6, 2011
Publication date	May 10, 2016
Grant date	May 10, 2016

Abstract

The present invention relates to a method of detecting synthetic mud filtrate in a downhole fluid including placing a downhole tool into a wellbore, introducing a downhole fluid sample into the downhole tool, analyzing the downhole fluid sample in the downhole tool, producing at least two filtrate markers from the analyzing of the downhole fluid sample and converting the at least two filtrate markers by vector rotation to a sufficiently orthogonal signal. The first pumped fluid sample giving initial plateau readings can be a proxy for 100% drilling fluid having an initial orthogonal signal and subsequent samples can be converted to orthogonal signals that are referenced to the first pumped fluid signal to give a calculation of percent contamination of the formation fluid.

First claim

The invention claimed is:

1. A method of detecting synthetic mud filtrate or determining filtrate contamination in a downhole fluid, comprising:
placing a downhole tool into a wellbore;
introducing a downhole fluid sample into the downhole tool; analyzing the downhole fluid sample in the downhole tool;
producing at least two filtrate markers from the analyzing of the downhole fluid sample; and
converting the at least two filtrate markers by vector rotation to a sufficiently orthogonal signal.

2. The method of claim 1 , wherein the analyzing comprises analyzing a first pumped fluid sample giving initial plateau readings that are a proxy for 100% drilling fluid having an initial sufficiently orthogonal signal.

3. The method of claim 2 , wherein subsequent samples pumped after the first pumped fluid sample are converted to sufficiently orthogonal signals that are referenced to the initial sufficiently orthogonal signal of the first pumped fluid sample to give a calculation of percent contamination of the formation fluid.

4. The method of claim 1 , wherein the analyzing comprises illuminating the downhole fluid sample with light from a light source and detecting light passing through the downhole fluid sample, and measuring the detected light to produce one or more filtrate markers.

5. The method of claim 4 , wherein the light emitted from the light source is of a sufficient wavelength to detect components selected from the group consisting of esters, ketones, olefins, amides, phosphorus, amines, thiocyanate, and combinations thereof.

6. The method of claim 4 , wherein the light source is an infrared light source producing infrared light.

7. The method of claim 6 , wherein the infrared light comprises wavelengths in the mid-infrared range.

8. The method of claim 1 , wherein the analyzing comprises using non-spectroscopic sensors selected from the group of ketone based, olefin based, amide based, phosphorus based, amine based, thiocyanate based, ester based, and combinations thereof.

9. The method of claim 3 , wherein the percent contamination is obtained without curve fitting the filtrate markers over time to predict the percent contamination at a given point in time.

10. A system for determining filtrate contamination in a formation fluid, comprising:
a downhole tool comprising at least one sensor to sense formation fluid samples;
a processor coupled to the at least one sensor;
wherein the processor is configured to analyze the formation fluid samples to produce at least two filtrate markers from data obtained from the at least one sensor and convert the at least two filtrate markers by vector rotation to a substantially orthogonal signal.

11. The system of claim 10 , wherein the processor is configured to analyze a first pumped formation fluid sample giving initial plateau readings that are a proxy for 100% drilling fluid having an initial sufficiently orthogonal signal.

12. The system of claim 11 , wherein signals from subsequent samples pumped after the first pumped formation fluid sample are converted by the computer processor to sufficiently orthogonal signals that are referenced to the initial sufficiently orthogonal signal of the first pumped formation fluid sample to give a calculation of percent contamination of the formation fluid.

13. The system of claim 10 , wherein the sensors are selected from the group consisting of ketone based, olefin based, amide based, phosphorus based, amine based, thiocyanate based, ester based, spectroscopic based, non-spectroscopic based, fluorescence based, acoustic based, density based, fluid conductivity based, and combinations thereof.

14. The system of claim 10 , wherein the sensors use spectral signals, non-spectral signals, or combinations of spectral and non-spectral signals, wherein the signals are stacked.

15. The system of claim 10 , wherein the percent contamination is obtained without curve fitting the filtrate markers over time to predict the percent contamination at a given point in time.

16. A method of analyzing a synthetic mud contaminated formation fluid utilizing spectroscopy, comprising:
placing a downhole tool into a wellbore;
introducing a formation fluid sample into the downhole tool;
analyzing the formation fluid sample in the downhole tool by illuminating the formation fluid sample by light emitting from a light source;
detecting light that passes through the downhole fluid sample;
measuring the detected light to produce at least two filtrate markers; and
converting the at least two filtrate markers by vector rotation to a sufficiently orthogonal signal.

17. The method of claim 16 , wherein the analyzing comprises analyzing a first pumped formation fluid sample giving initial plateau readings that are a proxy for 100% drilling fluid having an initial sufficiently orthogonal signal.

18. The method of claim 17 , wherein subsequent samples pumped after the first pumped formation fluid sample are converted to sufficiently orthogonal signals that are referenced to the initial sufficiently orthogonal signal of the first pumped formation fluid sample to give a calculation of percent contamination of the formation fluid.

19. The method of claim 16 , wherein the light emitted from the light source is of a sufficient wavelength to detect components selected from the group consisting of esters, ketones, amides, phosphorus, amines, thiocyanates, olefins, and combinations thereof.

20. The method of claim 16 , wherein the analyzing further comprises using non-spectroscopic sensors selected from the group consisting of ketone based, olefin based, amide based, phosphorus based, amine based, thiocyanate based, ester based, fluorescence based, acoustic based, density based, fluid conductivity based, and combinations thereof.

21. The method of claim 16 , wherein the analyzing is performed using spectral signals, non-spectral signals, or combinations of spectral and non-spectral signals, wherein the signals are stacked.

22. The method of claim 16 , wherein the percent contamination is obtained without curve fitting the filtrate markers over time to predict the percent contamination at a given point in time.

Assignees

• Jones Christopher Michael
• Engelman Robert E
• Pelletier Michael T
• Proett Mark A
• Rajasingam Thurairajasingam
• Halliburton Energy Services Inc

Inventors

• Jones Christopher Michael
• Engelman Robert E
• Pelletier Michael T
• Proett Mark A
• Rajasingam Thurairajasingam

Classifications

• E21B49/08 Primary

  Obtaining fluid samples or testing fluids, in boreholes or wells · CPC title

• E21B49/0875

  determining specific fluid parameters · CPC title

• E21B49/005

  Testing the nature of borehole walls or the formation by using drilling mud or cutting data · CPC title

• E21B2049/085

  Fixed Constructions · mapped topic