Passive microseismic monitoring has been a key technology used to map the stimulated portion of the reservoir through locating the sources of seismic waves generated by various modes of hydro-frac induced rock failure. The method was initially proposed as far back as the 70’s and published in a paper titled “The untapped potential of seismic imaging” by Edwards (Edwards TLE Round Table 1992). The best description I have heard of passive microseismic monitoring was given by Peter Duncan (Duncan SEG/AAPG DL 2008) where he compared microseismic to reflection seismic, as a stethoscope is to ultrasound recordings.
Consequently microseismic monitoring to map SRV for completion optimization, has forced the reflection seismologist into the domain of the engineer, and vice versa. This mapping is generally achieved by interpreting the cloud of microseismic event locations obtained from processing the P and/or S waves generated in the reservoir by fracking. This provides a backward view of bypassed pay potential for re-stimulation or a forward looking optimization of well and stage spacing to avoid costly over stimulation.
One may ask if microseismic monitoring of hydraulic fracture stimulation has replaced 3D reflection seismic as the most utilized geophysical method to appear in a decade? Is microseismic a breakthrough on the same scale as 3D?
These questions may be a function of one’s discipline as engineers embraced a fledgling microseimic technology well before geophysicists and in many cases in preference to surface 3D.
As a geophysicist, I was surprised by the fact that a technology that shares its earthquake seismological origins with reflection seismic, has been championed and advanced by experts outside of my discipline. After all, isn’t microseismic just downhole VSP or coarse 3D recording without a controlled surface source?
My late involvement in this technology can be explained by appreciating that passive monitoring of microseismic or earthquake events are essentially the same method at differing scales, and that my immersion in reflection seismic has left me behind and catching up with this trend.
However in the past few years the reflection seismologist, including me, has come in from the cold, so to speak, regaining his rightful place as the microseismic expert, as evidenced by numerous TLE and RECORDER publications by geophysicists. This trend continues for 2013 where three excellent focus articles in this RECORDER edition deal with some more advanced aspects in the application, processing and analysis of microseismic data.
The first article “Microseismic Case Study: Getting the most from your microseismic (MS) survey” by Michael Doerksen of Reservoir Imaging Ltd., describes how a junior oil and gas company used microseismic to optimally drain a Cardium sand resource play on their acreage in the Willesden Green area of Alberta to optimize well density and the number of frac stages.
Initial results showed microseismic events originating well outside of the Cardium zone both in height and lateral distance.
A basic requirement from microseismic is to obtain estimates of stimulated reservoir from event hypocentre clouds to establish the drainage volume contributing to production. Analysis of the initial hypocentre mapping showed that not all events represented connected permeability giving a overly optimistic estimate of stimulated rock volume (SRV).
The authors resolved this deficient yet basic requirement by making a series of assumptions to filter the located event data thereby yielding a more reasonable estimate of SRV to optimize well density. This ensured accurate prediction of efficient reservoir drainage for future pad design. This new approach to estimating SRV was further aided by the incorporation of a VSP to refine and calibrate the velocity model as well as integrating and ensuring the integrity of the surface 3D.
The second article “The influence of HTI anisotropy on micro seismic event location – a case study from a tight gas field in British Columbia” by Zuolin Chen, Barbara Cox and Colin Perkins of Shell Canada, describes the impact of HTI anisotropy on microseismic event location that is generally ignored but may have as large or greater effect than the more commonly investigated VTI case. The authors show how HTI degrades the location accuracy of microseismic events by distorting sensor orientation calibration from perforation shots prior to stimulation that may progressively invalidate the sensor rotation due to changes in HTI introduced by generation of hydraulic fractures. To solve this issue the author present a method to derive Thomsen parameters within the reservoir, which can be used for sensor orientation and microseismic event location calibration by obtaining the direction of the HTI axis of symmetry that enables an alternate estimation of the direction of aligned vertical fractures and/or maximum horizontal stress.
The final article “Unintentional Seismicity Induced by Hydraulic Fracturing” by Shawn Maxwell of Schlumberger describes the microseismicity that generates weak low magnitude (ML< 0) seismic arrivals used to estimate fracture propagation. These events are often challenging to even detect on surface let alone be felt. However, recently there have been well publicized cases and concerns associated with larger magnitude events that might be or have been felt on surface.
In this new context the article discusses particular aspects of existing and developing protocols as well as reviewing various aspects of anomalous seismicity associated with hydraulic fracturing. A very useful tutorial is presented about estimating source magnitudes, including possible processing pitfalls. Empirical energy and injection volume balances show promise as potential methods to estimate the largest possible magnitudes and help establish monitoring techniques for interpreting the seismicity.