We modifed a streamlined-based simulator based on the work of Batycky et al. (1997)
[7] to solve CO2 transport in aquifers and oil reservoirs. We then use this to propose
design strategy for CO2 injection to maximise storage in aquifers and to maximise both
CO2 storage and enhanced oil recovery (EOR) in oil reservoirs.
We first extended Batycky et al. (1997) [7]'s streamline simulator from two phases
(aqueous phase and hydrocarbon phase) and two components (water and oil) to a three-
phase (aqueous phase, hydrocarbon phase and solid phase) and four-component (water,
oil, CO2 and salt) simulator specialized for CO2 injection. We solved CO2 transport
equations in the hydrocarbon and aqueous phases along streamlines and in the direction
of gravity. To capture the physics of CO2 transport, in the hydrocarbon phase, we used
the Todd-Longsta® (1972) [112] model to represent sub-grid-block viscous fingering. We
implemented a thermodynamic model of mutual dissolution between CO2 and water and
resulting salt precipitation [104; 105]. The resultant changes in porosity and permeability
due to chemical reaction and salt precipitation were also considered. We accounted for two
cycles of relative permeability hysteresis (primary and secondary drainage and imbibition)
by applying two di®erent trapping models: Land (1968) [69] and Spiteri et al.(2005) [103].
Therefore, relative permeability changes and variations in the trapped non-wetting phase
saturations due to hysteresis can be updated on a block-by-block basis.
We then used this streamline-based simulator to design CO2 storage in aquifers. We
propose a carbon storage strategy where CO2 and brine are injected into an aquifer
together followed by brine injection alone. This renders 80-95% of the CO2 immobile
in pore-scale (10s ¹m) droplets within the porous rock; over thousands to billions of

years the CO2 may dissolve or precipitate as carbonate, but it will not migrate upwards
and so is e®ectively sequestered. The CO2 is trapped during the decades-long lifetime
of the injection phase, reducing the need for extensive monitoring for centuries. The
method does not rely on an impermeable cap rock to contain the CO2; this is only a
secondary containment for the small amount of remaining mobile gas. Furthermore, the
favorable mobility ratio between injected and displaced fluids leads to a more uniform
sweep of the aquifer leading to a higher storage e±ciency than injecting CO2 alone. This
design was demonstrated through one-dimensional simulations that were verified through
comparison with analytical solutions. We then performed simulations of CO2 storage in a
North Sea aquifer. We design injection to give optimal storage e±ciency and to minimise
the amount of water injected; for the case we study, injecting CO2 with a fractional
flow between 85 and 100% followed by a short period of chase brine injection to give
the best performance. Sensitivity studies were conducted for different rock wettabilities
and comparison with the Land trapping model. We found that the effectiveness of our
proposed strategy is very sensitive to the estimated residual CO2-phase trapping.
We then extended our study of the design of CO2 storage in aquifers to oilfields. We
again constructed analytical solutions to the transport equations accounting for relative
permeability hysteresis. We used this to design an injection strategy where CO2 and
brine are injected simultaneously followed by chase brine injection. We studied field-
scale oil production and CO2 storage for di®erent CO2 volumetric fractional flowrates.
While injecting at the optimum WAG ratio gives the fastest oil recovery, this allows
CO2 to channel through the reservoir, leading to rapid CO2 breakthrough and extensive
recycling of the gas. We propose to inject more water than optimum. This causes the
CO2 to remain in the reservoir, increases the field life and leads to improved storage of
CO2 as a trapped phase. Again, a short period of chase brine injection at the end of the
process traps most of the remaining CO2.
Finally, we investigated the e®ect of salt (halite) precipitation during dry, supercritical
CO2 injection using our modifed streamline-based simulator. In this study, pseudo one-
dimensional and two-dimensional homogeneous and heterogeneous systems were used to

study the sensitivity of di®erent parameters, which include relative permeability, grid
size and brine salinity to salt precipitation. In our three-dimensional model, based on
a geological model of a CO2 injection site, we constructed a near wellbore fine grid
model with almost 1.5 million grid cells. Simulations were conducted successfully, and
we found that salt precipitation can be a very important e®ect to consider when dry
CO2 is injected into a high salinity reservoir. In this reservoir, after only 2 years of CO2
injection, about 20% of permeability of the reservoir was reduced, which will seriously
reduce the injectivity of the injector and fluid flow within the reservoir.