EOR Signature in Carbonate Reservoirs from Extended Low-Salinity Waterflooding in Oman

Abstract

Low-salinity Enhanced Oil Recovery (EOR) signatures have been well proven by numerous lab and field trial studies (Zhang et al., 2007; Austad et al., 2008; Yousef et al., 2013; Al-Busafi et al., 2014). The evidence is very strong in clastic formations, even extending to full-field application evidence (Seccombe et al., 2010). However, low-salinity EOR in carbonate reservoirs is relatively underexplored and is still being studied in laboratory waterflooding tests and single-well trials. This is attributed to the lack of a single agreed physical model for the way low-salinity brine interacts with oil and carbonate rock surfaces under various subsurface conditions. Unlike sandstones, the reactive nature of carbonate rocks and the larger number of variables affecting the interactions have made the theory more complicated than clastic cases. For this reason, there are still some doubts about whether low-salinity EOR in carbonate rocks works or not. The conflicting arguments have made the oil industry very cautious of field applications in carbonates compared with sandstone reservoirs. This work presents field evidence of waterflooding performance from long periods of low-salinity waterflooding in carbonate reservoirs in Oman. The fields were subjected to low-salinity water injection that was fifty times less saline than formation water. Two approaches were adopted to assess the benefit of low-salinity water injection. In the first example, history matching of long-term low-salinity water injection was used to infer the shape of the relative permeability curves. Those curves were compared to the lab-derived versions and to those from analogous fields that were subjected to formation water injection. The other approach compared data for extended periods of water injection from two patterns from the same field: one pattern was injected with low-salinity water (~4,000 ppm) and the other pattern was injected with produced formation water (~150,000 ppm). Plots of recovery factor versus pore volumes of brine injected were compared to observe differences in performance. History matching results showed that the relative permeability curve had to be shifted from an oil-wet system to a water-wet system to achieve a good match. The resulting history-match curve was very different from the lab-measured relative permeability curve, which indicated an oil-wet system in this carbonate reservoir. The lab-derived curve was measured using a steady-state experiment with formation water. Furthermore, comparing the waterflood performance of the two areas with different salinities injected showed a clear distinction between their respective performance, with an 8-10% recovery factor difference after 0.3-0.4 pore volumes injected. Such observations support the argument that low-salinity waterflooding in carbonates has a long-term value that might not be easily observed from coreflooding tests in the laboratory or short field trials.