Multi-sensor workflow for evaluation of gas flow in multiple casing strings with distributed sensors

Patent metadata

Field	Value
Publication number	US-9784884-B2
Application number	US-201515111932-A
Country	US
Kind code	B2
Filing date	Sep 4, 2015
Priority date	Sep 10, 2014
Publication date	Oct 10, 2017
Grant date	Oct 10, 2017

Abstract

A gas presence and distance thereof are calculated using pulsed neutron data. A distance of a gas flow path and a velocity of the gas flow therein are calculated using distributed acoustic sensors. The gas saturation and distance, and gas velocity and distance obtained from the noise data are correlated to obtain a first calculated distance and velocity values. The distance and the velocity of the gas flow are calculated using distributed Doppler sensors. The distance and velocity values are compared with the first calculated distance and velocity values to obtain a second calculated distance and velocity values. The distance of the gas flow and the velocity of the gas flow are calculated using distributed temperature sensors. The distance and velocity values are compared with the second calculated distance and velocity values to determine a distance of a cement interface, and a velocity of a gas flow therein.

First claim

What is claimed is:

1. A method, comprising:
conveying a tool string into a wellbore, the wellbore at least partially lined with a first casing and a second casing concentrically overlapping a portion of the first casing, wherein a first annulus is defined between the first and second casings and filled with a first cement, and wherein a second annulus is defined between the second casing and the wellbore and filled with a second cement;
obtaining wellbore data from a pulsed neutron sensor included in the tool string and optical fiber measurements from one or more optical fibers included in a cable positioned in the wellbore;
determining a gas presence in a flow path located at a cement interface in the wellbore and a first distance of the flow path from the tool string using a pulsed neutron log borehole model and the wellbore data obtained from the pulsed neutron sensor;
calculating a second distance of the flow path from the tool string and a first velocity of the gas flow in the flow path using a distributed acoustic sensor (DAS) borehole model and distributed acoustic sensing measurements obtained from the one or more optical fibers;
correlating the first distance and the gas presence with the second distance and the first velocity and thereby obtaining a first calculated distance of the flow path and a first calculated velocity of the gas flow;
calculating a third distance of the flow path from the tool string and a second velocity of the gas flow in the flow path using a distributed Doppler sensor (DDS) borehole model and distributed Doppler sensing measurements obtained from the one or more optical fibers;
comparing the third distance and the second velocity with the first calculated distance and the first calculated velocity, respectively, to obtain a second calculated distance of the flow path and a second calculated velocity of the gas flow;
calculating a fourth distance of the flow path from the tool string and a third velocity of the gas flow in the flow path using a distributed temperature sensor (DTS) borehole model and distributed temperature sensing measurements obtained from the one or more optical fibers; and
determining a width of the cement interface, a distance of the cement interface from the tool string, and a velocity of a gas flow in the cement interface by comparing the fourth distance and the third velocity with the second calculated distance and the second calculated velocity, respectively.

2. The method of claim 1 , wherein obtaining wellbore data from the pulsed neutron sensor comprises obtaining an amount of gas saturation in the flow path.

3. The method of claim 1 , wherein obtaining the optical fiber measurements from the one or more optical fibers comprises one or more of obtaining amplitudes of noise signals detected by the one or more optical fibers from the wellbore, obtaining a frequency spectrum of the noise signals, obtaining a relative phase shift between the noise signals, obtaining frequency ratios of near and far noise signals, and obtaining power spectral density of the noise signals.

4. The method of claim 1 , wherein obtaining the optical fiber measurements from the one or more optical fibers comprises one or more of obtaining amplitude and frequency information of an acoustic wave as modified by the wellbore, and obtaining a Doppler frequency shift between an acoustic wave emitted into the wellbore and the modified acoustic wave.

5. The method of claim 1 , wherein obtaining the optical fiber measurements from the one or more optical fibers comprises one or more of obtaining a temperature of the wellbore, obtaining a temperature gradient of the wellbore, and obtaining a derivative of a temperature profile of the wellbore.

6. The method of claim 1 , further comprising updating at least one of the pulsed neutron log borehole model and the DAS borehole model when the gas presence in the flow path, the first distance of the flow path, the second distance of the flow path, and the first velocity of the gas flow do not conform with each other.

7. The method of claim 6 , further comprising recalculating one or more of the gas presence in the flow path, the first distance of the flow path, the second distance of the flow path, and the first velocity of the gas flow using a corresponding updated model.

8. The method of claim 1 , further comprising updating one or more of the pulsed neutron log borehole model, the DAS borehole model, and the DDS borehole model when a difference between the first calculated distance and the third distance and a difference between the first calculated velocity and the second velocity is greater than a predetermined value.

9. The method of claim 8 , further comprising recalculating one or more of the gas presence in the flow path, the first distance of the flow path, the second distance of the flow path, the first velocity of the gas flow, the third distance of the flow path, and the second velocity of the gas flow using a corresponding updated model.

10. The method of claim 1 , further comprising updating one or more of the pulsed neutron log borehole model, the DAS borehole model, the DDS borehole model, and the DTS borehole model when a difference between the second calculated distance and the fourth distance and a difference between the second calculated velocity and the third velocity is greater than a predetermined value.

11. The method of claim 10 , further comprising recalculating one or more of the gas presence in the flow path, the first distance of the flow path, the second distance of the flow path, the first velocity of the gas flow, the third distance of the flow path, the second velocity of the gas flow, the fourth distance of the flow path, and the third velocity of the gas flow using a corresponding updated model.

12. The method of claim 1 , further comprising obtaining the DTS borehole model from a static borehole model.

13. A well system, comprising:
a tool string and a cable positioned in a wellbore drilled through one or more subterranean formations, wherein the wellbore is at least partially lined with a first casing and a second casing concentrically overlapping a portion of the first casing, and wherein a first annulus is defined between the first and second casings and filled with a first cement, wherein a second annulus is defined between the second casing and the wellbore and filled with a second cement, wherein the tool string includes a pulsed neutron sensor, and wherein the cable includes one or more optical fibers used to obtain optical fiber measurements; and
a data acquisition system including a processor and a non-transitory computer readable medium, the tool string and the cable communicatively coupled to the data acquisition system, wherein the computer readable medium stores a computer readable program code that, when executed by the processor, configures the processor to:
operate the pulsed neutron sensor to obtain pulsed neutron log (PNL) data from the wellbore;
determine a gas presence in a flow path located at a cement interface in the wellbore and a first distance of the flow path from the tool string using a pulsed neutron log borehole model and the PNL data;
operate the data acquisition system to obtain distributed acoustic sensing measurements from the wellbore using the one or more optical fibers;
calculate a second distance of the flow path from the tool string and a first velocity of a gas flow in the flow path using a distributed acoustic sensor (DAS) borehole model and the distributed acoustic sensing measurements;
correlate the first distance and the gas presence with the second distance and the first velocity to obtain a first calculated d

Assignees

• Halliburton Energy Services Inc

Inventors

• Quintero Luis F

Classifications

• G01V1/226

  Optoseismic systems · CPC title

• E21B47/135

  using light waves, e.g. infrared or ultraviolet waves · CPC title

• E21B47/07

  Temperature · CPC title

• E21B47/005

  Monitoring or checking of cementation quality or level · CPC title

• G01V5/10 Primary

  using neutron sources {(neutron generating tubes H05H5/00; neutron sources using isotopes G21G4/00)} · CPC title