Microseismic signal processing

• US 6,947,843 B2
• Filed: 07/25/2002
• Issued: 09/20/2005
• Est. Priority Date: 08/07/2001
• Status: Expired due to Term

• Current Assignee: Schlumberger Technology Corporation (SLB)
• Original Assignee: Vetco Gray Controls Limited (General Electric Company)
• Inventors: Wilson, Stephen, Fisher, Andrew, Jupe, Andrew, Jones, Robert Hughes
• Primary Examiner(s): MCELHENY JR, DONALD E
• Application Number:
  US10/381,554
• Publication Number:
  US 20040008580A1
• Time in Patent Office: 1,153 Days
• Field of Search: 702/12, 702/13, 702/14, 702/15, 702/16, 702/18, 703/10, 367/73
• US Class Current: 702/13
• CPC Class Codes: G01V 1/01 Measuring or predicting earthquakes
• CPC Class Codes: G01V 1/306 for determining physical properties of the subsurface, e.g. impedance, porosity or attenuation profiles

Abstract

Signals from microseismic events are used to obtain a parameter of reservoir such as porosity, permeability or saturation.

Claims

1. A method of monitoring a reservoir by detecting a microseismic signal produced by a microseismic event, the method being applicable both for events induced by injection and extraction of fluid into and out of the reservoir, wherein a characteristic of a microseismic signal is used to investigate a process or property occurring at the source location of an individual microseismic event (as defined by a seismic source volume with a radius with the event located at the center of the volume).

2. A method according to claim 1, involving quantitative analysis of the seismic signal to obtain a reservoir parameter based on a theoretical model of the seismic source mechanism and/or estimation of a reservoir parameter based on an empirical relationship relating a time or frequency domain characteristic of the seismic signal to a known or derived reservoir property determined through an exploration method.

10. A method according to claim 1, the method including:

providing a plurality of seismic sensors located remote from a plurality of microseismic sources;

detecting microseismic signals from the plurality of microseismic sources;

comparing microseismic waveforms of the detected microseismic signals to a model of physical processes occurring at each of the microseismic sources;

deriving, responsive to the comparison, a source location in space and in time for each of the microseismic sources;

analyzing a frequency content of the microseismic signal to estimate an equivalent radius of a fracture plane generating the microseismic event; and

analyzing a polarity of each microseismic signal and relative amplitude of different microseismic phases at at least one of the plurality of seismic sensors, to thereby determine an orientation in space of the failure plane generating the microseismic event.

3. A method of monitoring a reservoir by detecting a microseismic signal produced by a microseismic event, the method being applicable both for events induced by injection and extraction of fluids into and out of the reservoir, wherein the spatial and temporal relationship and/or comparison of seismic waveforms between adjacent microseismic events is used to estimate a reservoir property in the region between and including the individual event locations.

4. A method according to claim 3, involving quantitative analysis of the seismic signal to obtain a reservoir parameter based on a theoretical model of the seismic source mechanism and/or estimation of a reservoir parameter based on an empirical relationship relating a time or frequency domain characteristic of the seismic signal to a known or derived reservoir property determined through an exploration method.

11. A method according to claim 3, the method including:

providing a plurality of seismic sensors located remote from a plurality of microseismic sources;

detecting microseismic events having similarity of microseismic waveforms, proximity in space, and proximity in time, the microseismic events indicating passage of fluid between adjacent microseismic locations;

determining the spatial and temporal relationship of the microseismic events to thereby estimate pressure front velocity and fluid conductivity; and

predicting fluid flow in the reservoir, responsive to the estimated fluid conductivity, to thereby enhance fluid production.

12. A method according to claim 3, the method including:

providing a plurality of seismic sensors located remote from a plurality of microseismic sources;

detecting microseismic events from the plurality of microseismic sources;

preselecting a volume containing the detected microseismic sources;

dividing the preselected volume into a plurality of smaller discrete volumes defining volume cells;

analyzing microseismic activity within each volume cell to thereby define each volume cell as either active or passive;

modeling a hydraulic connection between each active volume cell and the other active volume cell, the hydraulic connection having a length and a conductivity estimated from a spatial separation between the adjacent volume cells and seismic parameters used to determine volume cell activity, thereby forming a network of interconnected hydraulic connections defining a conductivity grid; and

inputting the conductivity grid into a preselected numerical reservoir model to predict reservoir fluid flow to thereby improve reservoir management and recovery.

13. A method according to claim 12, wherein the volume cells are cubic.

5. A method of monitoring a reservoir by detecting a microseismic signal produced by a microseismic event, the method being applicable both for events induced by injection and extraction of fluid into and out of the reservoir, wherein a microseismic signal is used to investigate a process occurring at any location between source and receiver locations at some point on a raypath of a wave traveling between source and receiver.

6. A method according to claim 5, which uses a means of separating the effect of a reservoir property on the seismic waveform from some specified point on the raypath from the integrated effect of all other points on the raypath between source and receiver.

7. A method according to claim 6, used to determine a reservoir parameter at some point or to estimate a parameter based on an empirical relationship relating a time or frequency domain characteristic of the seismic signal to a known or derived reservoir property determined through an exploration method.

14. A method according to claim 5, the method including:

providing a plurality of seismic sensors located remote from a plurality of microseismic sources;

preselecting a volume containing the microseismic sources;

assigning a raypath between each microseismic source and at least one of the plurality of seismic sensors, each raypath providing an average velocity of a microseismic waveform between the source and the sensor;

determining a point of an intersection of the intersecting raypath;

dividing the preselected volume into a plurality of discrete cells each having a cell length;

forming a matrix of equations relating average waveform velocity to waveform travel time over each cell and the cell length;

inverting the matrix to form a grid of velocities; and

relating the grid of velocities to reservoir properties, to thereby improve reservoir modeling.

8. A method of monitoring a hydrocarbon reservoir by detecting a microseismic signal produced by a microseismic event, the method being applicable both for events induced by injection and extraction of fluid into and out of the reservoir, wherein a microseismic signal from one or more events is used to investigate a process occurring at location remote from the seismic event and not necessarily on a raypath between the source and receiver.

9. A method according to claim 8, which involves the use of a single event to investigate a property or by considering the cumulative effect of many such events.

15. A method according to claim 8, the method including:

detecting a microseismic event from a microseismic source;

estimating shear displacement along a fault structure during a failure that produces the microseismic event from the received waveform; and

determining stress tensor rotations around the fault structure, responsive to the determined fault shear displacement.