INFLUENCE OF CAPILLARY PRESSURE ON CO 2 STORAGE AND MONITORING Juan E. Santos Work in collaboration with: G. B. Savioli (IGPUBA), L. A. Macias (IGPUBA), J. M. Carcione and D.Gei ((OGS) Trieste, Italy) Purdue University and Instituto del Gas y del Petróleo de la Univ. de Buenos Aires (IGPUBA), Argentina and Univ. Nac. de La Plata
Transcript
Slide 1
INFLUENCE OF CAPILLARY PRESSURE ON CO 2 STORAGE AND MONITORING
Juan E. Santos Work in collaboration with: G. B. Savioli (IGPUBA),
L. A. Macias (IGPUBA), J. M. Carcione and D.Gei ((OGS) Trieste,
Italy) Purdue University and Instituto del Gas y del Petrleo de la
Univ. de Buenos Aires (IGPUBA), Argentina and Univ. Nac. de La
Plata
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Introduction. I CO 2 sequestration in suitable geological
formations is one of the solutions to mitigate the greenhouse
effect. Saline aquifers are suitable as storage sites due to their
large volume and their common occurrence in nature. Numerical
modeling of CO 2 injection and seismic monitoring are important
tools to understand the long term behavior after injection and to
test the effectiveness of CO 2 sequestration.
Slide 3
Introduction. II The first industrial CO 2 injection project
started in 1996 is at the Sleipner gas field in Norway. The CO 2
separated from natural gas is being injected in a saline aquifer,
the Utsira formation a high permeable sandstone with several
mudstone layers that limit the vertical motion of the CO 2 From:
http://decarboni.se/publications
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Introduction. III We introduce a numerical procedure combining
simulations of: CO 2 injection and storage in saline aquifers.
Seismic monitoring of CO 2 migration in the subsurface. The
multiphase flow functions (relative permeability and capillary
pressure relations) are determined from on-site resistivity
measurements. In particular we analyze the sensitivity of the
spatial distribution of CO 2 and their seismic images due to
capillary pressure variations.
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1. Black-Oil simulator to model CO 2 injection and storage. 2.
Seismic monitoring using a viscoelastic model formulated in the
space-frequency domain that includes mesoscopic-scale attenuation
and dispersion effects. Multiphase Flow Functions A model to update
the petrophysical properties Methodology
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Mass conservation equation The Black-Oil formulation Darcys
Empirical Law
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The numerical solution was obtained employing the public domain
software BOAST. BOAST solves the flow differential equations using
IMPES (IMplicit Pressure Explicit Saturation), a finite difference
technique. The basic idea of IMPES is to obtain a single equation
for the brine pressure by a combination of the flow equations. The
system is linearized evaluating k r and P C at the saturations of
the previous time step. Once pressure is implicitly computed for
the new time step, saturation is updated explicitly. The Black-Oil
formulation - BOAST
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Multiphase Flow Functions Resistivity Index Using the log data
and the conductivity relation (Carcione et. al. JPSE, 2012): from
logs Then: at Utsira The multiphase flow functions were obtained
from the Resistivity Index (RI)
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Multiphase Flow Functions Relative Permeability Curves Relative
permeability curves are obtained from RI(S b ):
A Model to update the Petrophysical properties Carciones model
(Carcione et.al., IJRMMS, 2003)
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Seismic Modeling Mesoscopic Attenuation Effects Within the
Utsira formation and outside the mudstone layers, we determine the
complex and frequency dependent P-wave modulus at the mesoscale
using Whites theory for patchy saturation.
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Seismic Modeling Constitutive Relations
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Seismic Modeling Phase Velocities and Attenuation
coefficients
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Seismic Modeling A Viscoelastic Model for Wave Propagation
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Finite Element Method
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0,4 km depth 1,2 km length 10 km thickness Fractal Initial
Porosity Fractal Initial Permeability Low Permeability Mudstones
2,5D model Aquifer Model Utsira formation From:
http://www.sintef.no
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Initial Vertical Permeability Distribution [mD] Aquifer Model
Initial Vertical Permeability Within the formation there are
several mudstone layers which act as barriers to the vertical
motion of the CO 2.
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Sensitivity analysis - saturation maps after 3 years of
injection Pce=5kPaPce=200kPa
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Pce=5kPaPce=200kPa QpQp vpvp Sensitivity analysis Q p and v p
after 3 years of injection
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Pce=5kPaPce=200kPa 0 300 600 900 1200 Distance (m) Time (s) 0
300 600 900 1200 Distance (m) Time (s) Sensitivity analysis
synthetic seismograms after 3 years of injection
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Saturation maps up to 7 years of injection Pce=200kPa
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Synthetic seismogram after 7 years of injection Pce=200kPa Real
seismogram 0 300 600 900 1200 Distance (m) Time (s) 50ms 0 50
Time-lag (ms) Chadwick et. al., BGS, (2004)
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Conclusions The fluid-flow simulator yields CO 2 accumulations
below the mudstone layers and the corresponding synthetic
seismograms resemble the real data, where the pushdown effect is
clearly observed. Capillary forces affect the migration and
dispersal of the CO 2 plume; higher values of the threshold
capillary pressure Pce cause slower CO 2 upward migration and
thicker zones of CO 2 accumulations. Variations in capillary forces
induce noticeable changes in the seismic images of the Utsira
formation, clearly seen in the synthetic seismograms.