Methods and apparatus for optically measuring fluid compressibility downhole

• US 6,474,152 B1
• Filed: 11/02/2000
• Issued: 11/05/2002
• Est. Priority Date: 11/02/2000
• Status: Expired due to Term

• Current Assignee: Schlumberger Technology Corporation (SLB)
• Original Assignee: Schlumberger Technology Corporation (SLB)
• Inventors: Traboulay, Ian, Distefano, Thomas, McGowan, Robin, Mullins, Oliver C., Kurkjian, Andrew
• Primary Examiner(s): Williams, Hezron
• Assistant Examiner(s): WIGGINS, JOHN DAVID
• Application Number:
  US09/704,630
• Time in Patent Office: 733 Days
• Field of Search: 731/522.2, 731/522.4, 731/522.7, 731/525.2, 166/250.01, 166/254.2, 166/250.07, 175/50, 175/48, 175/41, 175/40, 250/255, 250/256, 250/338.5
• US Class Current: 73/152.22
• CPC Class Codes: G01N 2021/3536 using modulation of pressure or density
• 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

Abstract

The compressibility of a formation hydrocarbon sample is determined downhole by using a borehole tool to obtain the sample downhole, and, at two different pressures, subjecting the sample to near infrared illumination and conducting spectral absorption measurement of peaks at and/or around about 6,000 cm⁻¹ and/or at and/or about 5,800 cm⁻¹ (the absorption peaks of methane and crude oil respectively). The compressibility of the sample is determined from the change in the peak areas, the change in pressure, and the measured peak area itself. According to a preferred embodiment of the invention, the pressure is changed at least 2000 pounds per square inch (psi), and preferably 4000 or more psi between measurements.

Claims

1. A borehole apparatus for measuring downhole the compressibility of hydrocarbon fluid in a formation, comprising:

a) a testing region;

b) a conduit for directing the formation fluid into said testing region;

c) means for measuring pressure on the fluid in said testing region;

d) means for changing pressure on the fluid in said testing region;

e) a light source which emits at least near infrared rays into said testing region;

f) a spectral detector optically coupled to said testing region; and

g) a processing means coupled to said spectral detector and to said means for measuring pressure, said processing means for determining said compressibility of said hydrocarbon fluid as a function of a change in pressure determined from at least two measurements made by said means for measuring pressure and as a function of measurements made by said spectral detector.

2. A borehole apparatus according to claim 1, wherein:

said testing region is a transparent tube or chamber through which the hydrocarbon fluid flows and which is located between said light source and said spectral detector.

3. A borehole apparatus according to claim 1, wherein:

said spectral detector comprises means for measuring the intensity of light at at least one wavelength which has been transmitted through the fluid in said testing region.

4. A borehole apparatus according to claim 3, wherein:

said at least one wavelength comprises a plurality of wavelengths.

5. A borehole apparatus according to claim 3, wherein:

said at least one wavelength comprises approximately 1660 nanometers.

6. A borehole apparatus according to claim 1, wherein:

said spectral detector comprises means for measuring the intensity of light at at least one wavelength range which has been transmitted through the fluid in said testing region.

7. A borehole apparatus according to claim 6, wherein:

said at least one wavelength range comprises a range from approximately 1640 nm to approximately 1675 nm.

8. A borehole apparatus according to claim 1, wherein:

said change of pressure comprises a change of at least 2000 pounds per square inch (psi).

9. A borehole apparatus according to claim 3, wherein:

said processing means determines compressibility according to $\mathrm{\beta <br><br>}=\frac{-1}{\mathrm{\Psi <br><br>}}<br><br>{\left(\frac{\mathrm{\Delta <br><br>\Psi <br><br>}}{\mathrm{\Delta <br><br>}<br><br>\text{\hspace{1em}<br><br>}<br><br>P}\right)}_T<br><br>\text{\hspace{1em}<br><br>}<br><br>\mathrm{or}<br><br>\text{\hspace{1em}<br><br>}<br><br>\mathrm{\beta <br><br>}=\frac{1}{\mathrm{\Psi <br><br>}}<br><br>{\left(\frac{\partial <br><br>\mathrm{\Psi <br><br>}}{\partial <br><br>P}\right)}_T$

 

where β

is said compressibility of said fluid, Ψ

is a peak area at said at least one wavelength, Δ

P and ∂

P are said change in pressure, Δ

Ψ and

∂

Ψ

are a change in peak area, and T is a temperature.

10. A borehole apparatus according to claim 9, wherein:

.

said peak area is determined as a function of a known emission of said light source and of said measurements made by said spectral detector.

11. A borehole apparatus according to claim 1, wherein:

said means for changing pressure comprises at least one valve and a pump coupled to said conduit.

12. A method for determining the compressibility of hydrocarbon fluid in a formation, comprising:

a) obtaining a sample of said hydrocarbon fluid from said formation;

b) conducting a first spectral analysis of said sample at a first pressure to obtain first spectral results;

c) exposing said sample or an equivalent sample of hydrocarbon fluid to a second pressure different than said first pressure;

d) conducting a second spectral analysis of said sample or said equivalent sample at said second pressure to obtain second spectral results;

e) determining an indication of said compressibility of said hydrocarbon fluid from an indication of said first pressure, an indication of said second pressure, and said first and second spectral results.

13. A method according to claim 12, wherein:

said second pressure differs from said first pressure by at least 2000 pounds per square inch (psi).

14. A method according to claim 12, wherein:

said first spectral analysis comprises detecting an intensity of light transmitted through the sample at at least one near infrared wavelength, and said second spectral analysis comprises detecting a second intensity of light transmitted through the sample at said at least one near infrared wavelength.

15. A method according to claim 14, wherein:

said at least one near infrared wavelength comprises a plurality of near infrared wavelengths.

16. A method according to claim 14, wherein:

said at least one near infrared wavelength comprises approximately 1660 nanometers.

17. A method according to claim 12, wherein:

said first spectral analysis comprises detecting an intensity of light transmitted through the sample at at least one near infrared wavelength range, and said second spectral analysis comprises detecting a second intensity of light transmitted through the sample at said at least one near infrared wavelength range.

18. A method according to claim 17, wherein:

said at least one near infrared wavelength range comprises a range from approximately 1640 nm to approximately 1675 nm.

19. A method according to claim 14, wherein:

said indication of compressibility is determined according to $\mathrm{\beta <br><br>}=\frac{-1}{\mathrm{\Psi <br><br>}}<br><br>{\left(\frac{\mathrm{\Delta <br><br>\Psi <br><br>}}{\mathrm{\Delta <br><br>}<br><br>\text{\hspace{1em}<br><br>}<br><br>P}\right)}_T<br><br>\text{\hspace{1em}<br><br>}<br><br>\mathrm{or}<br><br>\text{\hspace{1em}<br><br>}<br><br>\mathrm{\beta <br><br>}=\frac{1}{\mathrm{\Psi <br><br>}}<br><br>{\left(\frac{\partial <br><br>\mathrm{\Psi <br><br>}}{\partial <br><br>P}\right)}_T$

 

where β

is said compressibility of said fluid, Ψ

is a peak area at said at least one wavelength, Δ

P and ∂

P are said change in pressure, Δ

Ψ and

∂

Ψ

are a change in peak area, and T is a temperature.

20. A method according to claim 12, wherein:

said first pressure and said second pressure are above a bubble point pressure of said sample.

21. A borehole apparatus for measuring downhole the compressibility of hydrocarbon fluid in a formation, comprising:

a) a testing region;

b) a conduit for directing the formation fluid into said testing region;

c) a sensor for measuring pressure on the fluid in said testing region;

d) means for changing pressure on the fluid in said testing region;

e) a light source which emits at least near infrared rays into said testing region;

f) a spectral detector optically coupled to said testing region; and

g) a processor coupled to said spectral detector and to said sensor, said processor for determining the compressibility of the formation fluid as a function of a change in pressure determined from at least two pressure measurements made by said sensor and as a function of measurements made by said spectral detector.