Wettability of Carbonate Reservoirs: Effects of Fluid and Aging

Abstract

As the production of hydrocarbons from the carbonate reservoir increases, there is a necessity to enhance oil recovery methods to increase recovery factors and improve the economic efficiency of field development. The knowledge of wettability's role and fluid distribution at the pore scale is required to comprehend the mechanisms for oil displacement from porous media. The X-ray computed micro-CT technology provides opportunities to study the complex fluid displacement process at the pore level. This work discusses wettability restoration in carbonate cores and its effect on fluid distribution in porous space. Wettability restoration refers to restoring the original wettability of the core after extraction. We investigate wettability change and two-phase fluid distribution at pore-scale with the help of micro-CT technique along with Amott spontaneous imbibition methods. The Amott spontaneous imbibition experiments performed on the core under ambient pressure. The micro-CT experiments conducted for steady flow core flooding experiments on harsh cleaned cores. The three-dimensional images acquired for dry core, core saturated with brine and kerosene followed by oil injection. For better visualization of the fluid-fluid and fluid-rock surface and to remove voxel artifacts, iodo-octane is mixed with oil with 10 % wt/wt. The experiments allow us to envisage the structures of fluid in each phase during the displacement of fluid in carbonate rocks with high resolution (3 μm/voxel). The novelty of this approach lies in efficiently capturing the CT images of the fluid distribution and its influence on wettability during the "core-aging" procedure and validating the results of it with the Amott imbibition wettability index. The initial wettability of harsh cleaned carbonate cores was identified as water-wet compare to mixed wettability for mild cleaned carbonates. Nevertheless, all the samples become strongly oil-wet regardless of the cleaning methods after long-term saturation with crude oil. The X-ray CT technique revealed the fast evolution of contact angle of brine corresponding the wettability changes to strong oil-wet after contact with crude oil under the reservoir conditions.

A Guide for Selection of Aging Time and Temperature for Wettability Alteration in Various Rock-Oil Systems

“…Results indicated that carbonates in general require less aging time to alter their wettability condition to oil-wet, around 1–7 days, compared with sandstones, around 14–21 days, based on the temperature and oil used. It took 10–14 days to alter the wettability of carbonate rock samples with temperatures ranging between 25 and 90 °C. ,,,,− On the contrary, it takes a longer duration ranging between 14 and 21 days at higher temperatures of 60–90 °C to change the rock sample wettability of sandstone. ,,,, …”

“…It took 10–14 days to alter the wettability of carbonate rock samples with temperatures ranging between 25 and 90 °C. 32 , 33 , 36 , 37 , 46 − 48 On the contrary, it takes a longer duration ranging between 14 and 21 days at higher temperatures of 60–90 °C to change the rock sample wettability of sandstone. 33 , 40 , 42 , 45 , 49 …”

“…Aging cores with crude oil is an approach to restoring original wettability conditions similar to that of reservoir conditions. 32 Aging time and temperature depend on several factors, including fluid composition, pressure, and lithology. Much of the literature mentions that 1000 h (42 days) is most acceptable as gaining time.…”