PetroTeach Free Webinar on Seismic Reservoir Characterization
GHGT_final_RE
1. Detectability of free-phase
migrating CO2
A rock physics and seismic modelling feasibility study
Rami Eid, Anton Ziolkowski, Mark Naylor, Gillian Pickup
3. Introduction
CO2 monitorability
Ability to detect structurally trapped CO2
successfully demonstrated
Detection of a migrating front is
moderately understood
Results in multi-phase fluid distributions
of different compressibilities
Seismic response depends on fluid type,
saturation and distribution
Primary seal
Secondary reservoir
Secondary seal
Overburden
Primary reservoir
Storage complex
Reservoir-seal pair
Storage site
Free-phase
migration
Migration
Leakage
4. Motivation
Understanding the range of variables
which affect the detectability of a
migrating front of CO2
Interplay between geology, geophysics
and petrophysics
Develop a workflow to aid in the
detection a loss of containment
Provide operators with an early warning
system
Primary seal
Secondary reservoir
Secondary seal
Overburden
Primary reservoir
Storage complex
Reservoir-seal pair
Storage site
Free-phase
migration
Migration
Leakage
5. Methodology
Assess the expected range of velocities
Patchy vs Uniform saturation distribution
2D elastic finite-difference wave
equation modelling
Front of vertically
ascending plume
7. Rock physics modelling - theory
Predict the change in elastic properties of the migrating
front
Gassmann’s equation: assumes immiscible and
homogeneously distributed phases throughout
Migrating CO2 is spatially heterogeneous, resulting in
partial fluid saturation
Result in two fluid-saturation end-members;
patchy and uniform distribution
Related to hydraulic diffusivity and diffusion length
suggests the spatial scales over which pore-pressure can
equilibrate during a seismic period
Obvious consequences for seismic velocity and impedance
8. Rock physics modelling - theory
Compressibility of CO2 directly affects reservoir
seismic velocity
Vp is heavily dependent on the model used.
Uniform saturation, Gassmann-Reuss
Sufficient time for wave induced pressure oscillations to
flow and relax – less stiff porous rock
9. Rock physics modelling - theory
Compressibility of CO2 directly affects reservoir
seismic velocity
Vp is heavily dependent on the model used.
Uniform saturation, Gassmann-Reuss
Sufficient time for wave induced pressure oscillations to
flow and relax – less stiff porous rock
Patchy saturation, Gassmann-Hill
Not enough time for wave-induced pore pressure
equilibrium during seismic period
patches of rock remain at different pressures
increase in material stiffness
predicts higher velocities
10. Rock physics modelling - theory
Compressibility of CO2 directly affects reservoir
seismic velocity
Vp is heavily dependent on the model used.
Uniform saturation, Gassmann-Reuss
Sufficient time for wave induced pressure oscillations to
flow and relax – less stiff porous rock
Patchy saturation, Gassmann-Hill
Not enough time for wave-induced pore pressure
equilibrium during seismic period
patches of rock remain at different pressures
increase in material stiffness
predicts higher velocities
Modified-patchy
Saturations constrained by rel-perm curves, limits for Swir
11. Compressibility of CO2 directly affects reservoir
seismic velocity
Vp is heavily dependent on the model used.
Uniform saturation, Gassmann-Reuss
Sufficient time for wave induced pressure oscillations to
flow and relax – less stiff porous rock
Patchy saturation, Gassmann-Hill
Not enough time for wave-induced pore pressure
equilibrium during seismic period
patches of rock remain at different pressures
increase in material stiffness
predicts higher velocities
Modified-patchy
Saturations constrained by rel-perm curves, limits for Swir
Highlights
range of velocities which could be encountered
importance of determining the most
appropriate model
Rock physics modelling - theory
Migrating
plume front
12. Rock physics modelling - application
Elastic properties of a migrating front
Assume both Modified-patchy and Uniform saturation
Uniform Saturation
Change in velocity
of -200 m/s at the
migrating front
Mod-patchy saturation
Change in velocity of
-50 m/s
15. Seismic forward modelling
Monitor survey
Amplitude changes Time shifts
Structurally trapped CO2
Migrating CO2 front
High amplitude change at 1780 m
Velocity push-down at 2200 m
No obvious change in amplitude
Uniform saturation model Modified-patchy saturation model
16. Seismic forward modelling
Geometry of structurally trapped CO2
Clear push-down below plume
Weak amplitude difference at the migrating
front
Time-lapse seismic sections
Reveal details not easily observed in
monitor section alone
Slight push-down below plume
Very weak amplitude change at the
migrating front
Time-lapse uniform saturation model Time-lapse modified-patchy saturation model
17. Seismic forward modelling
Geometry of structurally trapped CO2
Clear push-down below plume
Weak amplitude difference at the migrating
front
Time-lapse seismic sections
Reveal details not easily observed in
monitor section alone
Slight push-down below plume
Very weak amplitude change at the
migrating front
Time-lapse uniform saturation model Time-lapse modified-patchy saturation model
Clean sandstone model
Potential for detecting a migrating front?
18. Conclusions
Whilst this may seem like a negative result, CO2 plume rising in clean sandstone is the
hardest end-member to detect
Factors impacting on detectability:
Phase of CO2
Relative-permeability curves
Heterogeneity: capillary trapping
Knowledge of migration hotspots
For site appraisal, it is important to assess factors that
1. affect not only storage security and capacity, but
2. factors that will lead to more favourable detection of a loss of containment
Design and construction of monitoring
surveys – aiding in the detection of a
loss of containment
Editor's Notes
Co2 monitorability – measurement, monitoring and verification of injected co2 into the subsurface. This is done to demonstrate containment within the intended formation and identify any movement of co2 within the complex.
Ability for seismic methods to detect: this is due to change sin acoustic properties in the reservoir to the less dense and compressible co2
Develop a workflow: migrating from primary to secondary reservoir
Provide operators: allow for remediation activities to be undertaken such that the probability of a leak outside of storage complex is negligible.
For the work which I will be presenting today, we will be assessing the range in velocities which could be expected through the application of two saturation end-member fluid distribution models
Permedia’s BOS was used to simulate the migration of CO2 in the reservoir. CO2 was injected into secondary reservoir, and upon reaching the zone of weakness, resulted I migration into the secondary reservoir. We injected 0.1MT/yr for 20 years, injection well centre of the model, through 50m perf interval at 2000m.
Gassmann’s assumption: this is expected with systems which have come to equilibrium over geological timescales. This is not the case during co2 injection, which results in heterogeneous fluid distribution
Explain curve for each eg, uniform, sharp change at low saturations, nothing thereafter, etc
We are aware of that, but what we want to do is understand the factors which enhance the ability to detect migrating CO2.
