Formation Damage Due to CO2 Sequestration in Deep Saline Carbonate Aquifers
- Ibrahim Mohamed Mohamed (Texas A&M University) | Hisham A. Nasr-El-Din (Texas A&M University)
- Document ID
- Society of Petroleum Engineers
- SPE International Symposium and Exhibition on Formation Damage Control, 15-17 February, Lafayette, Louisiana, USA
- Publication Date
- Document Type
- Conference Paper
- 2012. Society of Petroleum Engineers
- 5.10.1 CO2 Capture and Sequestration, 6.5.7 Climate Change, 5.9.2 Geothermal Resources, 4.3.4 Scale, 1.6.9 Coring, Fishing, 5.1 Reservoir Characterisation, 5.5 Reservoir Simulation, 1.8 Formation Damage, 5.8.7 Carbonate Reservoir, 5.3.2 Multiphase Flow, 1.2.3 Rock properties, 5.1.2 Faults and Fracture Characterisation, 5.4.2 Gas Injection Methods, 6.5.2 Water use, produced water discharge and disposal, 5.4 Enhanced Recovery, 4.3.1 Hydrates
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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 structure.
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.
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