American Oil and Gas Reporter - September 2023 - 82

SpecialReport: CCS Feasibility Studies
geophysical surveys. Deep subsurface
monitoring focuses on tracking CO2 containment
in the reservoir and its movement
over time, and commonly utilizes techniques
such as 3-D seismic reflection,
pulsed neutron spectroscopy logging,
wellbore pressure and temperature logging,
fiber-optic measurements, electromagnetic
and resistivity surveys and tracer data.
None of these solutions are silver bullets.
Consider surface-based time-lapse
3-D seismic reflection and borehole-based
vertical seismic profile (VSP) surveys,
FIGURE 3A
Flowchart of the Poroelastic Model
Pore Pressure
Full coupling
traditional tools for monitoring CO2 in
laterally extensive conventional reservoirs.
These tools aim to detect changes in impedance
that occur as CO2 replaces insitu
fluids (brines or hydrocarbons).
Surface seismic has higher lateral resolution
than vertical resolution, whereas
VSP has high vertical resolution. Unfortunately,
decade-long 3-D seismic processing
and interpretation research on mudrocks
has shown that surface-based reflection
seismic data has limited ability to detect
fractures and gain insights into the fracture
Poroelastic Stresses &
Lagrangian Matrix
Deformation
Fault
Reactivation
system beyond the conventional studies
(for example, the presence and absence of
fractures in a study area). Such interpretations
do not provide high-resolution information
on fracture aperture or fracture fill,
which would impact CO2 injectivity.
Pulsed neutron capture logging also
has limitations. Like seismic, it's been
used in CCS over the years. The higher
the rock's porosity, the bigger the difference
of sigma among water, oil and CO2,
which helps distinguish them under different
saturation conditions over time.
The big challenge in using PNC in unconventional
shale reservoirs lies in its
inability to detect signals in low-salinity
and low-porosity reservoirs, such as the
Eagle Ford and Wolfcamp.
Wellbore pressure and temperature
measurements can provide valuable data
regarding CO2 plume migration, injectivity
and pressure buildup. CO2 injectivity and
storage capacity drops dramatically if
there is residual overpressure or pressure
buildup from CO2 injection. There are
several depleted mudrock reservoirs that
are either in hydrostatic or even underpressured
conditions (such as the Spraberry
in the Midland Basin) that are ideal candidates
for CCS.
FIGURE 3B
Mohr-Coulomb Shear-Failure Criterion
1,600
1,400
1,200
1,000
Failure
Envelope
800
Stress
State 2
600
Stress
State 1
400
200
500
82 THE AMERICAN OIL & GAS REPORTER
1,000
Normal Stress (kPa)
1,500
2,000
Either pressure/temperature gauges or
fiber optic (distributed acoustic sensing
or distributed temperature sensing) can
be deployed across the fractured reservoir
and confining zones (where fractures terminate)
to monitor CO2 movement out
of zone. Also, wellhead CO2 content and
pressure measurements can be used to
detect leakage during injection.
Other techniques used in conventional
reservoirs that can be applied to unconventional
reservoirs include time-lapse
electromagnetic, resistivity and passive
seismic surveys. In addition, tracer techniques
also can be used for monitoring.
New tools and data processing approaches
also could emerge. It is expected
that storing CO2 in the subsurface (including
fractures) will change geophysical and
geochemical responses, which we can
detect by using various surveys over time.
As an example, consider seismic diffraction
imaging. In recent studies, seismic
diffraction imaging has shown some promise
in recognizing fractures, fracture
geometry and connectivity better than
traditional seismic reflection data. Using
time-lapse diffraction imaging may be
Shear Stress (kPa)
American Oil and Gas Reporter - September 2023

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