Production logs from distributed acoustic sensors

• US 10,095,828 B2
• Filed: 03/08/2017
• Issued: 10/09/2018
• Est. Priority Date: 03/09/2016
• Status: Active Grant

• Current Assignee: Conocophillips Company (ConocoPhillips)
• Original Assignee: Conocophillips Company (ConocoPhillips)
• Inventors: Swan, Herbert W., Jin, Ge, Krueger, Kyle R., Roy, Baishali
• Primary Examiner(s): Bousono, Orlando
• Application Number:
  US15/453,730
• Publication Number:
  US 20180045040A1
• Time in Patent Office: 580 Days
• CPC Class Codes: E21B 47/02 Determining slope or direction
• 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: 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: G16Z 99/00 Subject matter not provided for in other main groups of this subclass

Abstract

A system and method for monitoring oil flow rates along a producing oil or gas well using a Distributed Acoustic Sensing fiber is described. This system uses the low-frequency component of the acoustic signal as a measurement of temperature variations within the well. The relative flow contributions can then be inferred from these temperature fluctuations.

Claims

1. A method of monitoring oil flow rates along a hydrocarbon reservoir comprising:

a) installing one or more fiber optic cables along a wellbore in a hydrocarbon formation;

b) installing one or more interrogators on at least one of said fiber optic cables;

c) interrogating at least one of said fiber optic cables with an interrogation signal during production;

d) obtaining one or more datasets of data from at least one of said interrogators;

e) converting one or more of said datasets from at least one of said interrogators into a continuous record;

f) transforming the continuous record with a low-pass filter to 1-100 milliHz while down sampling the data into a transformed well signal;

g) approximating flow velocities at a given depth by calculating the slope of temperature variation as a function of depth from the transformed well signal; and

h) estimating from the slope of temperature variation as a function of depth a cumulative production rate of hydrocarbons from said hydrocarbon formation.

2. The method of claim 1, further including the step of using said transformed well signal, temperature variation, or cumulative production rate in a reservoir modeling program to predict one or more reservoir performance characteristics including fracturing, production rates, total production levels, rock failures, faults, or wellbore failure.

3. The method of claim 1, further including the step of using said transformed well signal, temperature variation, or cumulative production rate to design and implement a hydraulic fracturing program, any enhanced oil recovery program, or a production plan.

4. The method of claim 1, including the further step of printing, displaying or saving the transformed well signal, temperature variation, or cumulative production rate.

5. A non-transitory machine-readable storage medium, which when executed by at least one processor of a computer, performs the steps of claim 1.

6. A method of monitoring oil flow rates along a hydrocarbon reservoir comprising:

a) installing one or more fiber optic cables along a wellbore in a hydrocarbon formation;

b) installing one or more interrogators on at least one of said fiber optic cables;

c) interrogating at least one of said fiber optic cables with an interrogation signal during production;

d) obtaining one or more datasets of data from at least one of said interrogators;

e) converting one or more of said datasets from at least one of said interrogators into a continuous record;

f) transforming the continuous record with a low-pass filter to 1-100 milliHz while down sampling the data into a transformed well signal;

g) quantitatively measuring flow velocities by removing the effect of constant-temperature produced fluids from the transformed well signal to generate a differentiated distributed acoustic sensing (DAS) signal;

h) computing a semblance function for the differentiated DAS signal; and

i) determining from the semblance function for the differentiated DAS signal a cumulative production rate of hydrocarbons from said hydrocarbon formation.

7. The method of claim 6, further including the step of using said transformed well signal, differentiated DAS signal, semblance function, or cumulative production rate in a reservoir modeling program to predict one or more reservoir performance characteristics including fracturing, production rates, total production levels, rock failures, faults, or wellbore failure.

8. The method of claim 6, further including the step of using said transformed well signal, semblance function, differentiated DAS signal, or cumulative production rate to design and implement a hydraulic fracturing program, any enhanced oil recovery program, or a production plan.

9. The method of claim 6, including the further step of printing, displaying or saving the transformed well signal, semblance function, differentiated DAS signal, or cumulative production rate.

10. A non-transitory machine-readable storage medium, which when executed by at least one processor of a computer, performs the steps of claim 6.

11. A method of monitoring oil flow rates along a hydrocarbon reservoir comprising:

a) installing one or more fiber optic cables along a wellbore in a hydrocarbon formation;

b) installing one or more interrogators on at least one of said fiber optic cables;

c) interrogating at least one of said fiber optic cables with an interrogation signal during production;

d) obtaining one or more datasets of data from at least one of said interrogators;

e) converting one or more of said datasets from at least one of said interrogators into a continuous record;

f) transforming the continuous record with a low-pass filter to 1-100 milliHz while down sampling the data into a transformed well signal;

g) quantitatively measuring flow velocities from the transformed well signal comprising;

i) use and initial estimate of fluid velocity to compute a traveltime function f(x),

ii) numerically form an inverse function through piece-wise interpolation,

iii) form a series of traveltime functions and their inverses,

iv) compute a semblance over a range of changes in time (δ

τ

),

v) set a new traveltime function f(x) at a trial function g(x, δ

τ

), and

vi) repeat (i)-(v) until convergence is achieved; and

h) determining from the measured flow velocities a cumulative production rate of hydrocarbons from said hydrocarbon formation.

12. The method of claim 11, further including the step of using said transformed well signal, semblance function, traveltime function, or cumulative production rate in a reservoir modeling program to predict one or more reservoir performance characteristics including fracturing, production rates, total production levels, rock failures, faults, or wellbore failure.

13. The method of claim 11, further including the step of using said transformed well signal, semblance function, traveltime function, or cumulative production rate to design and implement a hydraulic fracturing program, any enhanced oil recovery program, or a production plan.

14. The method of claim 11, including the further step of printing, displaying or saving the transformed well signal, semblance function, traveltime function, or cumulative production rate.

15. A non-transitory machine-readable storage medium, which when executed by at least one processor of a computer, performs the steps of claim 11.