An integrated experimental approach to quantify the oil recovery potential of seawater and low-salinity seawater injection in North Sea chalk oil reservoirs

In this study, the oil recovery potential of seawater (SW), SW with different ion compositions, low-salinity seawater (LSSW), and formation water (FW), is investigated, using chalk reservoir cores and crude oil from the North Sea. Furthermore, the impact of temperature on SW flooding performance is addressed.

A series of flooding experiments were conducted at reservoir conditions (2800 psi and 60 °C), followed by spontaneous imbibition tests. Secondary SW and FW flooding led to the same oil recovery. Tertiary SW injections, performed after secondary FW flooding and secondary LSSW injection, did not lead to any extra oil recovery at 60 °C.

Injecting SW at 100 °C did not lead to additional recovery either. Spiking the SO4-2 content of SW by four times, at 60 °C, did not show any additional oil production as well as increasing the concentration of Ca+2 and the Ca+2/Mg+2 ratio at 60 °C. Conversely, tertiary LSSW injection, after secondary SW injection, led to 2.5% OOIP additional oil recovery.

More importantly, secondary LSSW injection, compared to the secondary SW and FW injection, led to around 8% OOIP extra oil recovery. Consistently, the results of the imbibition test showed the same trend: tertiary LSSW imbibition, after secondary SW imbibition, led to 4.25% OOIP extra oil recovery. This study, through employing chalk reservoir cores and crude oil, reveals that LSSW flooding in examples of silica containing chalk reservoirs in the North Sea, has a better oil recovery potential compared to both SW and FW flooding.

This is in contrast to other published results as it will be discussed in the paper.