Passive seismic analysis for reservoir monitoring September 24, 2010 Capo Caccia, Sardinia, Italy D....
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Transcript of Passive seismic analysis for reservoir monitoring September 24, 2010 Capo Caccia, Sardinia, Italy D....
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