CO2 injection in carbonate formations causes a reduction in the well
injectivity, due to precipitation of the reaction products between CO2/
rock/brine. The precipitated material includes sulfate and carbonate scales.
The homogeneity of the carbonate rock, in terms of mineralogy and rock
structure, is an important factor that affects the behavior of permeability
changes during CO2 injection.
Limestone rocks represent the homogenous rock in this study, and include: Pink
Desert limestone and Austin chalk, which are mainly calcite. Silurian dolomite
(composed of 98% carbonate minerals, and 2% silicate minerals) and Indiana
limestone rock represent the heterogeneous rock, which have some vugs in their
Coreflood experiments were conducted to compare the behavior of the
permeability loss between these rocks. CO2 was injected with the water
alternating gas (WAG) technique. Different brines were examined including
seawater and no sulfate seawater. The experiments were run at a pressure of
1300 psi, a temperature of 200°F, and an injection rate of 5 cm3/min. A
compositional simulator tool (CMG-GEM) was used to confirm the experimental
results obtained in this study.
The results showed that for homogenous rocks, the presence of sodium sulfate in
the injected seawater is the major factor that causes formation damage, due to
calcium sulfate precipitation in CO2 environments. For dolomite rocks, higher
damage was noted, due to the reactions of CO2 with the silicate minerals. For
both homogenous and heterogeneous rocks, the source of damage for high
permeability cores is the precipitation of reaction products, while for low
permeability cores, water blockage increases the severity of formation damage.
The simulation study showed that the power-law exponent, and Carman-Kozeny
exponent between 5 and 6, can be used for homogenous carbonate rock to estimate
the change in permeability based on the change in porosity, for heterogeneous
rock a larger exponent was needed.
Change in well injectivity is a well known problem in CO2 injection wells,
either in enhanced oil recovery or sequestration projects (Grigg and Svec
2003). Well injectivity changes, due to relative permeability effects occurring
by multiphase flow, and chemical reactions between CO2/brine/rock.
Several publications in the have discussed the relative permeabilities for
CO2/brine systems (Dria et al. 2003; Bennion and Batchu 2006; 2008; Perrin et
al. 2009). Their results showed that for lower core permeability, higher
relative permeability for dense CO2 was shown at residual water saturation
(endpoint), and for the same carbonate formation, the lower the permeability,
the less CO2 can be injected into the formation. Grigg and Svec (2008)
estimated that the removal of CO2
saturation is more difficult and takes more time than establishing it.
The risk of water blockage, resulting from the trapping of water in the pore
throat is high, in low permeability water wet formations (Nasr-El-Din et al.
2002). Water blockage occurs when water blocks the macro pores, especially in
low permeability reservoirs. Water saturation close to irreducible water
saturation has a small effect on permeability, higher water saturations have a
more pronounced effect on the permeability since the larger pores are filled
with water (Gruber 1996).
Watts et al. 1982 reported that WAG injection of CO2 in the Hilly Upland
oilfield, which was composed mainly of low permeability carbonate rock
(permeability reported was 6.1 maximum, and less than 0.1 md minimum), caused
an increase in the injection pressure. The static bottomhole pressure was 635
psi, CO2 injection pressure was 1,252 psi at an injection rate of 70 RB/D, and
water injection pressure was 1,850 psi at an injection rate of 7 B/D.