Abstract
Significant portion of CO2 is dissolved in reservoir brine during CO2-Enhanced Oil Recovery. Dissolved CO2 forms an acidic environment which could modify rock-fluid interaction. One of the phenomena that could happen due to this interaction is clay swelling which may affect enhanced oil recovery performance. Several experiments were conducted in a number of sandstone core samples, i.e. Imbibition test, Core flood test, Conductivity test, and pH measurement. Imbibition test was conducted to evaluate CO2-saturated brine (approached with carbonic acid) performance toward oil recovery during five days measurement compared with brine imbibition performance. Moreover, core flood experiment was run to determine the effect of dissolved CO2 in brine on injection in sandstone. This is simulated by injecting brine (base case) followed by carbonic acid under 68.3 OC. Thus, conductivity and pH of the imbibed fluids (before & after running imbibition test) were measured to justify occurrence of cation exchange. Interpretation of imbibition test indicated that imbibing carbonic acid, at pH value of about four, resulted in loss of oil recovery about 15% compared with brine due to formation damage caused by clay swelling as sandstone contains clay. The existence of this phenomenon was confirmed by flow resistance at low pH in core sample which was higher than that in brine. This apparent plugging was expected due to severe clay swelling. Meanwhile, the existence of such phenomenon was also clarified with conductivity and pH measurement as there was a great amount of cation exchange.It can be inferred from this study that the rock-fluid interaction from CO2-saturated brine can result in adverse effect, such as injectivity problem and loss of recovery. This finding must be considered in planning CO2 EOR operations, especially when facing condition of watered out oil zone.
Highlights
Carbon dioxide (CO2) injection in the formations is one of several proposed methods for enhanced oil recovery
Performance of dissolved CO2 in water during injection leads to loss of performance. This is indicated by loss of oil recovery at static condition and higher flow resistance than base case
This happens as a result of interaction between dissolved CO2 in water and clay mineral. This interaction leads to severe clay swelling phenomenon as large amount of cation are being exchanged
Summary
Carbon dioxide (CO2) injection in the formations is one of several proposed methods for enhanced oil recovery. There are various typical operations of this injection in the oil industry, such as CCS (Carbon Capture and Storage), WAG (Water Alternating with Gas), CO2-Foaming, Miscible Injection, Immiscible Injection, CWI (Carbonated Water Injection), and Huff & Puff. Through those processes, many physical and chemical processes are known to occur both during and after CO2 injection, including diagenetic chemical reactions and associated permeability changes. Variability in rock types responses suggests that CO2 injection will induce changes in intrinsic rock properties such as porosity, permeability and wettability This is due to coupled physical and chemical processes that occur during the interaction between CO2 and rock minerals. Other potential phenomenon that may happen include severe formation damage due to clay reactivity that can be attributed to pH reduction from dissolved CO2 in brine
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