Passive seismic analysis for reservoir monitoring

September 24, 2010

Capo Caccia, Sardinia, Italy

D. Gei, L. Eisner, P. Suhadolc

Outline

• Hydraulic stimulation of reservoirs

• Passive seismic monitoring

• Surface star array data: some examples

• Focal mechanism inversion of microseismic events

• P-wave traveltime inversion for VTI media

Hydraulic stimulation of reservoirs

• It is injection of fluids under high pressure in order to overcome minimum stress

and open a hydraulic fractures, either by opening existing fractures or producing

new ones.

• It increases the permeability of the rock from microdarcy to millidarcy range.

• The fluid injected into the formation is typically composed of brine (95%),

additives, proppant (e.g. resin-coated sand, ceramic materials).

• The stimulated volume can extend several hundred meters around the well. The

dimensions, extent, and geometry of the induced fractures are controlled by

pump rate, pressure, and viscosity of the fracturing fluid.

• Reservoir hydraulic stimulations usually induce (significant) microseismic

activity.

Hydraulic stimulation is a technique to induce fractures in hydrocarbon and

geothermal reservoirs.

Perforation shots

(picture after API Guidance Document HF1, Hydraulic Fracturing Operations – Well Construction and Integrity Guidelines, First Edition, October 2009)

Perforation shotsLow permeability, hydrocarbon-rich formation

Stage 2 Stage 1

Perforation shots serve to connect wellbore and formation through opening in casing

ToeHeel

Fluid injection

Hydraulic stimulation

(picture after API Guidance Document HF1, Hydraulic Fracturing Operations – Well Construction and Integrity Guidelines, Fisrt Edition, October 2009)

Microseismic events

Stage 2 Stage 1

Anisotropy analysis (P and S waves)

Passive seismic monitoring of reservoirs consists in “listening” to the subsoil during oilfield operations (e.g. production, hydraulic stimulation, CO2 injection).

Passive seismic for reservoir monitoring

Location of events and clustering

Focal mechanisms

Map fracture system Cap rock integrityFault mapping (reservoir compartmentalization)

Fracture characterization

Fracture orientationFracture density and aspect ratio

Microseismic signals can be recorded by downhole sensors or surface star arrays of receivers.

Vertical array of 3C geophones (8-12 receivers) in a monitoring well.

Hundreds of receivers disposed in a star shaped array

(from Warpinski, 2009)

Monitoring well Treatment well

~300 m

Dep

th (

kft)

> source depth

Easting (kft)

Northing (kft)

Receivers

Treatment wells

Microseisms

(picture from www.microseismic.com)

Treatment well (deviated)

Hmax

Data example

Microseismic event 1

Perforation shot

Microseismic event 1

Lines 1 - 10

Processing performed Bandpass freq filter (2,7,60,70) HzAgc for visualization

Lines 1 - 10

Processing performed Bandpass freq filter (2,7,60,70) HzAgc for visualization

Polarity flip Polarity flip

Polarity flip Polarity flip

Microseismic event 1

Red line: frequency peak of the spectrum for each seismic trace

Data from line 10 (1C)Raw data

Line 10Line 10

Polarity flip source location

Time window width: 0.032 s

Microseismic event 1: frequency analysis of the seismic signals

Perforation shot

Direct arrivals from the perforation shot

Direct waves from the well headSurface waves from the well head

Perforation shot

ReceiversWell head

Perforation shot

Focal mechanisms

Focal mechanisms: event 1

Focal mechanism: oblique dip-slip fault

OK

Focal mechanism: strike slip fault

Focal mechanisms: event 6

Vertical Transverse Isotropy (polar anisotropy)

Anisotropic material: properties (e.g. seismic velocities) depend on direction. Vertical transverse isotropy can be related to fine layering in sedimentary basins or to shales.

Thomsen parameters (weak anisotropy)

5 independent elasticity constants (c11, c33, c44, c66, c13)

picked arrival time

P-wave traveltime inversion for homogeneous VTI media

one-way vertical traveltime

normal moveout velocity Anellipticity (Alkhalifah and Tsvankin, 1995)

P-wave velocity // symmetry axis

Experimental traveltimes

• Computed traveltimes (t0=-0.005 =0.1 =-0.1 )

• Computed traveltimes (t0=0.007 =0.2 =0.3 )

• Computed traveltimes (t0=0 =0.1 =0.22 )

*origin time

offset (horizontal projection of

source-receiver distance)

, , VP0

Perforation shot

P-wave traveltime inversion of perforation shot data

P-wave velocity profile

P-wave traveltime inversion of perforation shot data

Traveltimes from experimental data (layered anisotropic ? medium)

,

Traveltimes from synthetic data (ray tracing - isotropic layered medium)

,

Effective velocity for traveltime inversion

P-wave traveltime inversion from experimental data

Experimental dataInversion results: vtit0 = -0.244 s= 0.2734, 0.1172RMS4.0 ms

Picked arrival times

Tim

e (s

)

Time residualsExperimental and theoretical traveltimes - Line 1

P-wave traveltime inversion from synthetic data

Picked arrival times

Tim

e (s

)

Time residualsSynthetic and theoretical traveltimes - Line 1

Synthetic dataInversion results: VTIt0 = -0.001 s= 0.1217, 0.0148RMS1.1 ms

P-wave traveltime inversion from synthetic data

Experimental dataInversion results: VTIt0 = -0.244 s= 0.2734, 0.1172RMS4.0 ms

Picked arrival times

Tim

e (s

)

Time residualsSynthetic and theoretical traveltimes - Line 1

Synthetic dataInversion results: VTIt0 = -0.001 s= 0.1217, 0.0148RMS1.1 ms

Conclusions

This dataset is characterized by non-unique focal mechanism

The reservoir and/or the overburden are affected by polar anisotropy

Bibliography

Alkhalifah, T., and I. Tsvankin, 1995, Velocity analysis for transversely isotropic media: Geophysics, 60, 1550-1566.

API Guidance Document HF1, Hydraulic Fracturing Operations – Well Construction and Integrity Guidelines, First Edition, October 2009 (http://www.gwpc.org/e-library/documents/general/APi%20Hydraulic%20Fracturing%20Guidance%20Document.pdf)

Fischer, T., Hainzl, S., Eisner, L., Shapiro, S.A. and Le Calvez, J., 2008a, Microseismic signatures of hydraulic fracture growth in sediment formations: observations and modeling. Jour. Geoph. Res., 113, B02307, doi:10.1029/2007JB005070.

Grechka, V., 2009, Applications of seismic anisotropy in the oil and gas industry, EAGE Publications bv.

Jupe, A.J., Jones, R.H., Wilson, S.A., and Cowles, J.F., 2003, Microseismic monitoring of geomechanical reservoir processes and fracture-dominated fluid flow, Fracture and In-Situ Stress Characterization of Hydrocarbon Reservoirs, Geological Society, London, Special Publications.2003, Ameed, M.S. (Ed); 209: 77-86.

Maver, K.G., Boivineau, A.S., Rinck, U., Barzaghi, L., and Ferulano, F., Real time and continuous reservoir monitoring using microseismicity recorded in a live well, First Break, 27, 57-61.

Thomsen, L., 1986, Weak elastic anisotropy, Geophysics, 51, 1954–1966.

Warpinski, N., 2009, Microseismic Monitoring: inside and out, JPT, November 2009, 80-85.

We are grateful to Microseismic Inc. for supporting and providing us with the dataset. We thank Vladimir Grechka for providing us with

the P-wave traveltime inversion code.

Acknowledgments