In situ optical computation fluid analysis system and method

• US 8,237,920 B2
• Filed: 02/19/2010
• Issued: 08/07/2012
• Est. Priority Date: 12/09/2004
• Status: Active Grant

• Current Assignee: Halliburton Energy Services Incorporated (Halliburton Company)
• Original Assignee: Halliburton Energy Services Incorporated (Halliburton Company)
• Inventors: Jones, Christopher M., Elrod, Louis W.
• Primary Examiner(s): Geisel, Kara E
• Application Number:
  US12/708,740
• Publication Number:
  US 20100265509A1
• Time in Patent Office: 900 Days
• Field of Search: 356 72- 73, 356/445, 356/436
• US Class Current: 356/73
• CPC Class Codes: E21B 47/114 using light radiation
• CPC Class Codes: E21B 49/08 Obtaining fluid samples or testing fluids, in boreholes or wells
• CPC Class Codes: G01N 21/15 Preventing contamination of the components of the optical system or obstruction of the light path
• CPC Class Codes: G01N 21/27 using photo-electric detection G01N21/31 takes precedence; circuits for computing concentration logarithmic circuits G06G7/24; photometric circuits in general G01J
• 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 21/552 Attenuated total reflection
• CPC Class Codes: G01N 21/85 Investigating moving fluids or granular solids
• CPC Class Codes: G01N 33/2823 Raw oil, drilling fluid or polyphasic mixtures
• CPC Class Codes: Y10T 436/21 Hydrocarbon

Abstract

A multivariate optical element (MOE) calculation device is used in an apparatus for determining a property of petroleum in real time flowing in a pipe in petroleum field stream pipes or pipe line. Multiple apparatuses are provided for determining the amount of each of a plurality of properties. An internal reflectance element (IRE) can be used to determine the property of the petroleum from a surface of the petroleum flowing in a pipe. A cleaning apparatus can be provided to clean the surface of the IRE in the pipe and a turbulence generator can be provided in the pipe to insure homogeneity of the petroleum being analyzed prior to analysis. A bellows may be provided in the apparatus housing to compensate for pressure differentials between the housing and the flowing petroleum in the pipe. Various embodiments are disclosed.

Claims

1. A method, comprising:

directing light to interact with a dynamic and moving stream of fluid, including crude petroleum flowing in a stream, as part of first and second measurement procedures, and causing the fluid to produce interacted light from the directed light associated with each of the measurement procedures;

dividing the interacted light associated with each of the measurement procedures into reflected light and transmitted light, the reflected and transmitted light each having an intensity;

producing first and second signals, respectively based on the intensity of the transmitted and reflected light associated with the first measurement procedure, and producing third and fourth signals, respectively based on the intensity of the transmitted and reflected light associated with the second measurement procedure; and

determining at least two different properties of the dynamic and moving stream of fluid based on the first, second, third, and fourth signals, including determining properties of the crude petroleum flowing in the stream in a down hole environment,

wherein the causing, dividing, and producing steps are performed in situ at the stream.

2. The method of claim 1, wherein determining a first property includes subtracting the second signal from the first signal, and

wherein determining a second property includes subtracting the fourth signal from the third signal.

3. The method of claim 1, further comprising providing turbulence to the dynamic and moving stream of fluid upstream of a location associated with directing the light, to provide homogeneous distribution of components in the fluid receiving the directed light.

4. The method of claim 1, further comprising mechanically cleaning deposits resulting from the dynamic and moving stream of fluid on one or more portions of a conduit.

5. The method of claim 1, further comprising determining existence of an unknown adverse component affecting one or more of the first, second, third, and fourth signals.

6. The method of claim 1, wherein directing the light includes directing the light to interact with the dynamic and moving stream of fluid flowing through a conduit in a subsurface well.

7. The method of claim 1, wherein the at least two properties are selected from the group consisting essentially of:

asphaltene, saturates, resins, aromatics, solid particulate content, hydrocarbon composition and content, gas composition C1-C6 and content, CO₂, H₂S and correlated PVT properties including gas-oil ratio, bubble point, density, a formation factor, viscosity, a gas component of a gas phase of petroleum, total stream percentage of water, gas, oil, solid particles, solid types, oil finger printing, reservoir continuity, oil type, and water elements, and wherein the water elements consist essentially of;

ion composition and content, anions, cations, salinity, organics, pH, mixing ratios, tracer components, and contamination.

8. A system, comprising:

at least first and second apparatus coupled to a pipe system located in a down hole environment, each of the apparatus configured to direct light to a flowing fluid including a stream of crude petroleum in the pipe system, as part of a first measurement procedure associated with the first apparatus, and a second measurement procedure associated with the second apparatus, to cause the fluid to produce interacted light;

a turbulence generator in the pipe system upstream from the first and second apparatus;

one or more detectors located in the down hole environment for detecting reflected light and transmitted light from the interacted light, and configured to generate a first electrical intensity output signal responsive to the reflected light and a second electrical intensity output signal responsive to the transmitted light; and

a signal processing arrangement for determining a first property of the flowing fluid from the first and second electrical intensity output signals corresponding to the first measurement procedure, and a second, different property of the flowing fluid from the first and second electrical intensity output signals corresponding to the second measurement procedure.

9. The system of claim 8, wherein the one or more detectors include:

a first detector to detect energy associated with reflected light; and

a second detector to detect energy associated with transmitted light.

10. The system of claim 8, further comprising a cleaning arrangement for cleaning a surface of the pipe system.

11. The system of claim 8, further comprising an indicator in the flowing fluid to measure a parameter of the fluid.

12. The system of claim 8, wherein the turbulence generator includes at least one of a plurality of vanes or an apertured member, secured to the pipe system for receiving the flowing fluid.

13. The system of claim 8, wherein the signal processing arrangement is located remote from the first and second apparatus.

14. The system of claim 8, further comprising a remote alarm indicator including an audio indicator or a display, the alarm indicator responsive to the first and/or the second electrical intensity output signals.

15. The system of claim 8, wherein the first and second properties are selected from the group consisting essentially of:

asphaltene, saturates, resins, aromatics, solid particulate content, hydrocarbon composition and content, gas composition C1-C6 and content, CO₂, H₂S and correlated PVT properties including gas-oil ratio, bubble point, density, a formation factor, viscosity, a gas component of a gas phase of petroleum, total stream percentage of water, gas, oil, solid particles, solid types, oil finger printing, reservoir continuity, oil type, and water elements, and wherein the water elements consist essentially of;

ion composition and content, anions, cations, salinity, organics, pH, mixing ratios, tracer components, and contamination.

16. The system of claim 8, wherein the a down hole environment includes a well or a portion of a pipe line.

17. The system of claim 8, wherein the first and second apparatus are coupled to the pipe system at or adjacent to a common flow location.

18. A method, comprising:

directing light to interact with a dynamic and moving stream of fluid, including crude petroleum flowing in a stream, in a subsurface well, and causing the fluid to produce detectable interacted light from the directed light;

directing the interacted light to an optical element;

detecting at least two of (i) light reflected from the optical element, (ii) light transmitted by the optical element, and (iii) the interacted light directed to the optical element; and

determining at least one property of the dynamic and moving stream of fluid using detected information about at least two of the light reflected, the light transmitted, and the interacted light, including determining at least one property of the crude petroleum flowing in the stream located in the subsurface well,

wherein the causing, directing, and detecting are performed in situ at the stream.

19. The method of claim 18, wherein detecting the light reflected and the light transmitted includes generating first and second output light signals representing respective reflected and transmitted light, and

wherein determining the at least one property of the fluid includes processing the first and second signals.

20. The method of claim 18, wherein determining the at least one property of the fluid includes processing information about the interacted light, the light reflected, and the light transmitted.

21. The method of claim 18, wherein directing the interacted light to the optical element includes directing the interacted light to two or more optical elements, and

wherein determining the at least one property of the fluid includes using information about light detected from the two or more optical elements.

22. The method of claim 18, wherein the optical element is a multivariate optical element.

23. The method of claim 18, further comprising causing disorder to the dynamic and moving stream of fluid upstream of a location associated with directing the interacted light.

24. The method of claim 18, wherein detecting the light transmitted and the light interacted includes generating first and second output light signals representing respective transmitted and interacted light, and

wherein determining the at least one property of the fluid includes processing the first and second signals.

25. The method of claim 18, wherein detecting the light reflected and the light interacted includes generating first and second output light signals representing respective reflected and interacted light, and

wherein determining the at least one property of the fluid includes processing the first and second signals.