Real-time compositional analysis of hydrocarbon based fluid samples

Patent metadata

Field	Value
Publication number	US-9638681-B2
Application number	US-201113249535-A
Country	US
Kind code	B2
Filing date	Sep 30, 2011
Priority date	Sep 30, 2011
Publication date	May 2, 2017
Grant date	May 2, 2017

Abstract

Accurate, real-time formation fluids analysis can be accomplished using the systems and techniques described herein. A fluid analyzer includes a first mode of analysis, such as an optical analyzer, configured to determine a physical (optical) property of a fluid sample. The fluid analyzer also includes another mode of analysis, such as a composition analyzer, such as a gas chromatograph, configured to determine a component composition of the fluid sample. A data processor is configured to determine a quantity, such as a weight percentage, of a target component of the fluid sample in response results obtained from the first and second modes of analysis. Beneficially, the results are obtained at least in near real-time, allowing for interim results, such as results from the first analyzer to be used for one or more of tuning the compositional analyzer and for implementing quality control.

First claim

We claim:

1. A fluid analyzer for evaluating a fluid sample, the fluid analyzer comprising:
an optical analyzer adapted to receive at least a portion the fluid sample, the optical analyzer configured to determine an optical property of the fluid sample and to provide an optical analyzer output signal indicative of the determined optical property;
a composition analyzer adapted to receive at least a portion of the fluid sample, the composition analyzer configured to determine a component composition of the fluid sample and to provide a composition analyzer output signal indicative of the determined component composition; and
a data processor in communication with each of the optical analyzer and the composition analyzer, the data processor configured to determine a quantity of a target component within the fluid sample using (i) a quantity of a reference component within the fluid sample obtained from the optical analyzer output signal, (ii) a response area of the reference component obtained from the composition analyzer output signal, and (iii) a response area of the target component obtained from the composition analyzer output signal.

2. The fluid analyzer of claim 1 , wherein the data processor is configured to determine the quantity of the target component (W i GC ) according to:

W
i
GC

⁡

(
%
)

=

A
i
GC

×

R
i
GC

×

W
Ref
IFA

A
Ref
GC

×

R
Ref
GC

where: W i GC =the quantity of the target component;
A i GC =the response area of the target component obtained from the composition analyzer output signal;
A ref GC =the response area of the reference component obtained from the composition analyzer output signal;
W ref IFA =the quantity of the reference component determined from the optical analyzer output signal;
R i GC =a composition analyzer detector response factor for the target component; and

R ref GC =a composition analyzer detector response factor for the reference component.

3. The fluid analyzer of claim 1 , wherein the optical analyzer comprises an optical absorption spectrometer.

4. The fluid analyzer of claim 1 , wherein the composition analyzer comprises a gas chromatograph.

5. The fluid analyzer of claim 1 , wherein the composition analyzer is configurable based on the optical analyzer output signal.

6. The fluid analyzer of claim 1 , wherein each of the optical analyzer and composition analyzer is adapted for use downhole, within a wellbore, such that the fluid sample is obtainable in situ.

7. The fluid analyzer of claim 1 , further comprising a multiphase flowmeter adapted to receive at least a portion the fluid sample outside of a wellbore producing the fluid sample, at least one of the optical analyzer and composition analyzer receiving the fluid sample from the multiphase flowmeter.

8. The fluid analyzer of claim 1 , wherein the fluid sample comprises hydrocarbons.

9. A method for analyzing a fluid, comprising:
receiving a fluid sample;
determining an optical property of the fluid sample using optical analysis;
determining a quantity of a reference component within the fluid sample using the optical property;
determining a component composition of the fluid sample using gas chromatographic analysis, wherein the determining the component composition comprises: (i) generating a chromatogram of the fluid sample, (ii) determining a response area for a target component in the chromatogram, and (iii) determining a response area for the reference component in the chromatogram; and
determining a quantity of target component using the component composition of the fluid sample and the quantity of the reference component.

10. The method of claim 9 , wherein determining the optical property of the fluid sample comprises subjecting the fluid sample to optical absorption spectrometry.

11. The method of claim 9 , wherein quantifying the target component comprises evaluation of the algorithm:

W
i
GC

⁡

(
%
)

=

A
i
GC

×

R
i
GC

×

W
Ref
IFA

A
Ref
GC

×

R
Ref
GC

where: W i GC =the quantity of target component;
A i GC =the response area of the target component from the chromatogram;
A ref GC =the response area of the reference component from the chromatogram;
W ref IFA =the quantity of reference component;
R i GC =a gas chromatography response factor for the target component; and
R ref GC =a gas chromatography response factor for the reference component.

12. The method of claim 9 , further comprising deriving from the determined optical property, one or more other properties selected from the group consisting of: weight percentage of CH 4 component, weight percentage of C 2 H 6 —C 5 H 12 components, collectively; weight percentage of C 6 +, collectively; formation pressure; formation temperature; gas-oil ratio; and condensate-gas ratio.

13. The method of claim 9 , wherein the acts of receiving a fluid sample, determining an optical property, and determining the component composition are accomplished downhole, within a wellbore.

14. The method of claim 9 , further comprising:
passing the fluid sample through a multiphase flowmeter, wherein the method is performed outside of a wellbore producing the fluid sample.

15. The method of claim 9 , further comprising:
pre-configuring a gas chromatograph based on the determined optical property of the fluid sample, wherein the gas chromatograph is adapted for determining the component composition of the fluid sample.

16. The method of claim 9 , further comprising:
comparing the determined optical property with the determined component composition, wherei

Assignees

• Zhdaneev Oleg
• Harrison Christopher
• Zuo Youxiang
• Zhang Dingan
• Steinecker William H
• Lambertus Gordon R
• Bostrom Neil
• Schlumberger Technology Corp

Inventors

• Zhdaneev Oleg
• Harrison Christopher
• Zuo Youxiang
• Zhang Dingan
• Steinecker William H
• Lambertus Gordon R
• Bostrom Neil

Classifications

• G01N33/2823 Primary

  Raw oil, drilling fluid or polyphasic mixtures · CPC title

• E21B49/10 Primary

  using side-wall fluid samplers or testers · CPC title

• G01N21/359

  using near infrared light · CPC title

• G01N2030/8854

  involving hydrocarbons · CPC title

• G01N30/8658

  Optimising operation parameters · CPC title