METHOD AND SYSTEM FOR MONITORING FLUID FLOW IN A CONDUIT

• US 20160265345A1
• Filed: 10/27/2014
• Published: 09/15/2016
• Est. Priority Date: 10/28/2013
• Status: Active Grant

• Current Assignee: Shell USA Incorporated (Shell Plc)
• Original Assignee: Shell Oil Company (Shell Plc)
• Inventors: IN 'T PANHUIS, Petrus Hendrikus Maria Wilhemus, KUSTERS, Roel Marie, ROY, Dayeeta, MUSTAFINA, Daria, DEN BOER, Johannis Josephus
• Granted Patent: US 10,240,455 B2
• Time in Patent Office: Days
• US Class Current: 1/1
• CPC Class Codes: E21B 47/107 using acoustic means
• CPC Class Codes: E21B 47/113 using electrical indications; using light radiations
• CPC Class Codes: E21B 47/135 using light waves, e.g. infrared or ultraviolet waves
• CPC Class Codes: G01F 1/7086 using optical detecting arrangements
• CPC Class Codes: G01F 1/712 using auto-correlation or cross-correlation detection means
• CPC Class Codes: G01H 9/004 using fibre optic sensors light guides per se G02B6/00, acousto-optical devices specially adapted for gating or modulating in optical wave guides G02F1/125
• CPC Class Codes: G01V 2210/1429 Subsurface, e.g. in borehole or below weathering layer or mud line

Abstract

A method for monitoring fluid flow in a conduit comprises:

• • acoustically coupling an optical fiber to the conduit adjacent one or more flow restrictions (R₁-R₄) in the conduit;
  • inducing a Distributed Acoustic Sensing (DAS) assembly to measure an acoustic noise signature (SNR_1-4) generated in the fiber by the fluid flowing through each flow restriction (R₁-R₄);
  • deriving the fluid flow rate of the fluid (Q_I, Q_I+II) flowing through each flow restriction (R₁-R₄) from the measured acoustic noise signature (SNR_1-4); and
  • displaying the derived fluid flow rate (Q_I, Q_I+II) at a fluid flow rate monitoring display.

Claims

1. A method for monitoring fluid flow in a conduit, the method comprising:

acoustically coupling an optical fiber to the conduit adjacent to a flow restriction in the conduit;

inducing a Distributed Acoustic Sensing (DAS) assembly to measure an acoustic noise signature generated in the optical fiber by the fluid flowing through the flow restriction;

deriving the fluid flow rate of the fluid flowing through the flow restriction from the measured acoustic noise signature; and

displaying the derived fluid flow rate at a fluid flow rate monitoring display.

2. The method of claim 1, wherein the fluid flow rate Q is derived from the measured acoustic noise signature SNR following empirical correlations of McKinley, which correlate a number of empirical calibration parameters that depend on the number of flow restrictions.

3. The method of claim 2, wherein the empirical correlations of McKinley comprise the formula:

SNR=A+B.Q^N

, wherein A, B and N are empirically determined calibration parameters.

4. The method of claim 2, wherein the empirically determined calibration parameters A, B and N and other empirical calibration parameters are determined by a multi-rate production test wherein the gas and liquid production is measures at surface by means of a test separator or multiphase flowmeter, or by a flow test wherein a production logging tool is inserted in the conduit in the vicinity of the flow restriction and the fluid flow rate Q through the flow restriction is varied and measured by the production logging tool while the acoustic noise signature SNR is measured by the optical fiber and DAS interrogator assembly.

5. The method of claim 2, wherein the optical cable and DAS assembly is induced to measure the acoustic noise signature SNR of acoustic signals in different frequency bands of 1-10, 10-200, 200-2000 and 2000-5000 Hz transmitted by the fluid flow through the flow restriction to the optical fiber.

6. The method of claim 1, wherein the conduit is a hydrocarbon fluid transportation conduit arranged within or connected to a hydrocarbon fluid production well or a fluid injection conduit connected to or arranged in a fluid injection well through which fluid is injected into a hydrocarbon fluid containing formation.

7. The method of claim 6, wherein the conduit is arranged downhole in the hydrocarbon fluid production well or in the fluid injection well.

8. The method of claim 7, wherein a plurality of artificial flow restrictions, such as venturi-inserts, are arranged along at least part of the length the conduit.

9. The method of claim 8, wherein the flow restrictions have different flow resistivities.

10. The method of claim 8, wherein the flow restrictions are arranged downstream of a production zone or upstream of an injection zone of the well and the method is used to measure the amount of fluid produced from or injected into the formation in that zone.

11. A system for monitoring fluid flow in a conduit, the system comprising:

an optical fiber which is acoustically coupled to an outer surface of the conduit adjacent to a flow restriction in the conduit;

a Distributed Acoustic Sensing (DAS) assembly which is configured to measure an acoustic noise signature generated in the fiber by the fluid flowing through the flow restriction; and

a fluid flow monitoring display for displaying the fluid flow rate of the fluid flowing through the flow restriction derived from the measured acoustic noise signature.

12. The system of claim 11, wherein the system further comprises a computer readable medium, which when connected to a computer, causes the computer to derive the fluid flow rate Q from the measured acoustic noise signature SNR using the formula:

SNR=A+B.Q^N

, wherein A, B and N are empirically determined calibration parameters.

13. The system of claim 11, wherein the conduit is a hydrocarbon fluid transportation conduit arranged within or connected to a hydrocarbon fluid production well or a fluid injection conduit connected to or arranged in a fluid injection well through which fluid is injected into a hydrocarbon fluid containing formation.

14. The system of claim 13, wherein the conduit is a well tubing arranged downhole in the hydrocarbon fluid production well or in the fluid injection well.

15. The system of claim 14, wherein at least two flow restrictions with different flow resistivities are arranged in the well tubing downstream of each production zone or upstream of each injection zone of the well and the system is configured to measure the amount of fluid produced from or injected into the formation in that zone.