Experimental investigation of CO2 injection side effects on reservoir properties in ultra tight formations

CO2 injection can be an effective technique for increasing oil recovery from unconventional reservoirs. Laboratory studies and field tests have supported the viability of this method; however, some chemical reactions can occur due to the interaction of the injected CO2 with brine and reservoir rock minerals, which can impact and alter several reservoir attributes. Understanding possible CO2-induced reservoir petrophysical property changes is crucial for enhanced oil recovery (EOR) and gas storage. Two Middle Bakken (MB) and two Three Forks (TF) formation samples were tested to investigate changes in rock wettability, Pore Size Distribution (PSD), and effective porosity before and after exposure to CO2. We used the contact angle technique to measure the wettability state with and without CO2 exposure. The results indicate that CO2 can alter wettability and increase the hydrophilicity in both MB and TF samples. The Nuclear Magnetic Resonance (NMR) spectroscopy technique was used to determine fluid distribution before and after CO2 injection. The results confirm that carbonic acid can dissolve portions of the dolomite, calcite, and feldspar in the rock and create new micro- and nanopores. The microporosity increased by 52% and 33% for two MB samples and 10% and 22% for two TF samples, respectively, after one cycle of CO2 injection. Based on the NMR results, the effective porosity of the MB and TF samples decreased from 5.3% to 3.8% and 7.6%–6.3%, respectively, after four CO2 cycles. The dissolved CO2 can react with rock minerals and form precipitates that block some pores. This study aimed to provide a better understanding of the fundamental mechanisms that control oil recovery using CO2 injection in unconventional reservoirs.