Systems and methods for making optimized borehole acoustic measurements

Patent metadata

Field	Value
Publication number	US-9798031-B2
Application number	US-201114111288-A
Country	US
Kind code	B2
Filing date	Aug 9, 2011
Priority date	Aug 9, 2011
Publication date	Oct 24, 2017
Grant date	Oct 24, 2017

Abstract

A system and method for measuring a formation property in a wellbore is disclosed. In the method, an acoustic measurement tool is introduced into a wellbore. The acoustic measurement tool may include a transmitter and a plurality of sensors. At least one of the plurality of sensors may be positioned in a non-uniform spacing configuration. The transmitter may transmit energy into the formation. The plurality of sensors may measure energy received from the formation. Additionally, a time semblance of the formation may be determined using at least one time semblance algorithm generalized for non-uniform sensor spacing.

First claim

What is claimed is:

1. A system for measuring a time semblance of a formation, comprising:
a transmitter, wherein the transmitter transmits energy into the formation;
a plurality of sensors comprising a plurality of consecutive sensors, wherein the plurality of sensors measures energy received from the formation, wherein at least one of the plurality of consecutive sensors is positioned in a non-uniform axial spacing configuration, and wherein the non-uniform axial spacing configuration of the at least one of the plurality of consecutive sensors is determined, at least in part, using a time semblance algorithm, wherein the time semblance algorithm comprises determining

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wherein t is a time, wherein N is a total number of the plurality of sensors, Ns is a total number of slowness values, i is a value from 1 to N, j is a value from 1 to Ns, z i denotes a position of sensor i along a tool, s j represents a slowness value of a waveform in the formation, and A(s j ,z i ,t) represents a progression of the waveform for a particular slowness s j ; and
a data processing unit including at least one time semblance algorithm, wherein the data processing unit receives measurements from the plurality of sensors and processes the measurements to determine a time semblance of the formation.

2. The system of claim 1 , wherein the non-uniform spacing configuration comprises one of a spacing with one non-uniformly spaced sensor and a spacing determined using at least one non-linear mathematical expression.

3. The system of claim 1 , wherein the non-uniform spacing configuration comprises spacing optimized to reduce aliasing.

4. The system of claim 3 , wherein the time semblance algorithm is a min-max time semblance algorithm.

5. The system of claim 3 , wherein the time semblance algorithm is a sum time semblance algorithm.

6. The system of claim 3 , wherein the spacing optimized to reduce aliasing is determined using at least one iterative step.

7. The system of claim 1 , wherein the at least one time semblance algorithm includes a time semblance algorithm for non-uniform sensor spacing.

8. The system of claim 1 , wherein the at least one time semblance algorithm comprises one of either a sum time semblance algorithm or a min-max time semblance algorithm.

9. A method for measuring a time semblance of a formation, comprising:
introducing an acoustic measurement tool into a wellbore, wherein the acoustic measurement tool includes a transmitter and a plurality of sensors comprising a plurality of consecutive sensors, wherein at least one of the plurality of consecutive sensors is positioned in a non-uniform axial spacing configuration, and wherein the non-uniform axial spacing configuration of the at least one of the plurality of consecutive sensors is determined, at least in part, using a time semblance algorithm, wherein the time semblance algorithm comprises determining

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Assignees

• Donderici Burkay
• Guner Baris
• Halliburton Energy Services Inc

Inventors

• Donderici Burkay
• Guner Baris

Classifications

• G01V1/48 Primary

  Processing data · CPC title