Method And Apparatus For Identifying Fluid Attributes

• US 20150204189A1
• Filed: 03/13/2013
• Published: 07/23/2015
• Est. Priority Date: 06/29/2012
• Status: Active Grant

• Current Assignee: Schlumberger Technology Corporation (Schlumberger NV)
• Original Assignee: Schlumberger Technology Corporation (Schlumberger NV)
• Inventors: Indo, Kentaro, Pop, Julian, Hsu, Kai
• Granted Patent: US 9,441,481 B2
• Time in Patent Office: Days
• US Class Current: 1/1
• CPC Class Codes: E21B 47/113 using electrical indications; using light radiations
• CPC Class Codes: E21B 49/088 combined with sampling
• CPC Class Codes: G01N 21/31 Investigating relative effect of material at wavelengths characteristic of specific elements or molecules, e.g. atomic absorption spectrometry G01N21/72 takes precedence
• CPC Class Codes: G01N 21/359 using near infrared light
• CPC Class Codes: G01V 8/00 Prospecting or detecting by optical means
• CPC Class Codes: G01V 8/10 Detecting, e.g. by using light barriers by reflection from the object G01S17/00

Abstract

A method for identifying the type of a sampled formation fluid, such as a hydrocarbon, is provided. In one embodiment, the method includes measuring absorbance by a sample of a formation fluid at multiple wavelengths of electromagnetic radiation with a spectrometer. The method also includes distinguishing between multiple fluid types to identify a fluid type of the sample most likely to match an actual fluid type of the sample based on the measured absorbance at two or more wavelengths of the multiple wavelengths. Additional systems, devices, and methods are also disclosed.

Claims

1. A method comprising:

measuring absorbance by a sample of a formation fluid at a plurality of wavelengths of electromagnetic radiation with a spectrometer; and

distinguishing between multiple fluid types to identify a fluid type of the sample most likely to match an actual fluid type of the sample based on the measured absorbance at two or more wavelengths of the plurality of wavelengths.

2. The method of claim 1, wherein distinguishing between the multiple fluid types to identify the most likely fluid type of the sample based on the measured absorbance at the two or more wavelengths includes comparing the measured absorbance at a first wavelength of the two or more wavelengths to the measured absorbance at a second wavelength of the two or more wavelengths.

3. The method of claim 2, wherein comparing the measured absorbance at the first wavelength to the measured absorbance at the second wavelength includes calculating an absorbance ratio based on the measured absorbance at the first wavelength and the measured absorbance at the second wavelength and using the calculated absorbance ratio to distinguish between the multiple fluid types.

4. The method of claim 3, wherein using the calculated absorbance ratio to distinguish between the multiple fluid types includes comparing the calculated absorbance ratio to a set of benchmark data of calculated absorbance ratios for different types of formation fluids to identify the most likely fluid type of the sample.

5. The method of claim 3, comprising adjusting both the measured absorbance at the first wavelength and the measured absorbance at the second wavelength with a spectral offset before calculating the absorbance ratio.

6. The method of claim 5, wherein the spectral offset is determined from measured absorbance by the sample at a third wavelength of the plurality of wavelengths.

7. The method of claim 1, comprising determining a probability that the actual fluid type of the sample is the identified, most likely fluid type of the sample.

8. The method of claim 7, comprising determining an additional probability that the actual fluid type of the sample is instead another fluid type of the multiple fluid types different from the identified, most likely fluid type.

9. The method of claim 1, comprising collecting the sample of the formation fluid from a well using a downhole tool.

10. The method of claim 9, wherein measuring absorbance by the sample of the formation fluid at the plurality of wavelengths of electromagnetic radiation with the spectrometer and distinguishing between the multiple fluid types to identify the most likely fluid type of the sample based on the measured absorbance at the two or more wavelengths of the plurality of wavelengths are performed in the well by the downhole tool.

11. A method comprising:

irradiating a formation fluid with light having at least a first wavelength and a second wavelength;

detecting a portion of the light that is transmitted through the formation fluid;

calculating a first optical density of the formation fluid with respect to the first wavelength of light and a second optical density of the formation fluid with respect to the second wavelength of light;

deriving an optical density ratio from the first optical density and the second optical density; and

characterizing a physical attribute of the formation fluid based on the optical density ratio.

12. The method of claim 11, wherein characterizing the physical attribute of the formation fluid based on the optical density ratio includes empirically correlating the optical density ratio to the physical attribute of the formation fluid through comparison of the optical density ratio to a database of optical density ratios and associated physical attributes for previously analyzed, known fluid samples.

13. The method of claim 12, comprising storing the database of optical density ratios and associated physical attributes for previously analyzed, known fluid samples in a memory device of a downhole tool to enable the downhole tool to perform the comparison of the optical density ratio to the database while within a well.

14. The method of claim 12, comprising creating the database of optical density ratios and associated physical attributes from data derived through Pressure-Volume-Temperature analysis of the previously analyzed, known fluid samples.

15. The method of claim 11, wherein characterizing a physical attribute of the formation fluid includes characterizing a fluid type of the formation fluid.

16. An apparatus comprising:

a downhole sampling tool including an intake configured to receive a formation fluid within the downhole sampling tool and a downhole fluid analysis module having a spectrometer and configured to enable measurement of optical densities of the received formation fluid at different wavelengths of electromagnetic radiation; and

a controller operable to characterize a fluid type of the received formation fluid using the optical densities of the received formation fluid.

17. The apparatus of claim 16, wherein the controller is operable to characterize the fluid type of the received formation fluid by calculating an optical density ratio based on two of the different wavelengths and comparing the calculated optical density ratio to a database, encoded in memory of the controller, of associations between optical density ratios and types of formation fluids.

18. The apparatus of claim 16, wherein the controller is operable to characterize the fluid type of the received formation fluid as at least one of a dry gas, a wet gas, a retrograde gas, or an oil.

19. The apparatus of claim 16, wherein a detector of the spectrometer is configured to detect near-infrared wavelengths and the controller is operable to determine the fluid type of the received formation fluid using optical densities of the received formation fluid at the near-infrared wavelengths.

20. The apparatus of claim 16, wherein the controller is provided within the downhole sampling tool.