Microseismic monitoring
Learning objectives
- Explain the source of microseismic events during hydraulic fracturing
- Describe the P–S arrival-time inversion for event location
- Quote typical event counts and magnitudes per frac stage
- Link event-cloud shape to Stimulated Reservoir Volume (SRV)
Hydraulic fracturing injects 10–20 MPa of fluid pressure into a rock formation through a horizontal well. Above a critical stress threshold, the rock cracks. Each micro-crack radiates small P and S wavelets — a “microseism”. Nearby receivers pick them up; picking arrival times and inverting locates each event. The cloud of located events maps the rock volume actually stimulated by the frac — the Stimulated Reservoir Volume (SRV).
Event physics
Magnitudes typically M -3 to M -1 (occasionally M 0–+1 if a fault reactivates). That is 1 to 10 million times smaller than a felt earthquake. The radiated signal is a small wavelet 10–20 ms long; the pattern is a double-couple focal mechanism characteristic of a micro-fault slipping. Multi-stage horizontal fracs produce 5–20 thousand locatable events over 5–10 days of pumping.
Location inversion
Pick P and S arrival times at every receiver. P travels at vₚ, S at vₛ ≈ vₚ/1.7. Time difference Tₛ–Tₚ gives hypocentre distance. Multi-receiver intersection gives direction. The ray-traced, velocity-model-driven inversion typically locates each event to 10–30 m horizontally and 15–40 m vertically — resolution limited by picker SNR and the near-far offset mix of the receiver array.
Decisions from the cloud
Three operational decisions depend on the map. (1) Stage-to-production correlation: which stages produced stimulation clouds that match later production from the well? (2) Frac-height containment: did the cloud stay in the target formation or did it grow into the seal / aquifer / neighbouring producer? (3) Fault-reactivation screening: do events align on a planar feature larger than a typical stage cloud? If yes, a fault is being re-activated and injection pressure should be backed off.
Monitor-well geometry
Typical monitor wells sit 200–1500 m from the injection. Too close: signal clips the receivers. Too far: location error explodes because radii becomes near-parallel. Industry sweet spot is 500–1000 m. Surface microseismic arrays exist too, but with 100–1000× worse SNR than downhole — typically used when a monitor well is not available.
References
- Aki, K., Richards, P. G. (2002). Quantitative Seismology (2nd ed.). University Science Books.
- Sheriff, R. E., Geldart, L. P. (1995). Exploration Seismology (2nd ed.). Cambridge University Press.
- Yilmaz, Ö. (2001). Seismic Data Analysis: Processing, Inversion, and Interpretation of Seismic Data (2 vols.). SEG Investigations in Geophysics 10.