A wide range of outcrop sandstones and carbonates have been tested for waterflood response to one twentieth dilution of synthetic seawater, using a single crude oil that gave high response to low salinity flooding for a reservoir rock. The tested outcrop rocks included 17 sandstones and 6 carbonates. Gas permeabilities ranged from 1.49 to 7,187 mD and porosities from 10 to 39%. The average reduction in residual oil for tertiary response was only 1.5% OOIP with the highest being 5.8% OOIP; some rocks showed no response. After testing, three of the outcrop rocks that responded to injection of low salinity brine were restored by cleaning and re-aging with crude oil using procedures comparable to those commonly used in restoration of reservoir cores. When re-tested, the response to low salinity flooding was eliminated for two of the cores and significantly reduced for the third core. Companion plugs for 6 of the sandstones and 3 carbonates were tested for increased oil recovery using low salinity connate and injected brine; this data provided comparison with the measurements for high salinity connate and injection brine. Six of the plugs showed increase in recovery for the low salinity waterfloods, and three showed decrease. Results are also summarized for the effects of reduction in salinity for 11 sandstone cores taken from five reservoirs and 8 carbonate cores all taken from the same reservoir. Comparison between results for outcrop and reservoir cores, including literature data, indicates that overall response to low salinity flooding is significantly higher for the reservoir cores.

Sequential waterflooding refers to cycles of flooding for which initial water saturation is re-established after a waterflood by flow of crude oil followed by further waterflooding. In previously reported examples of sequential waterflooding, cores were neither cleaned nor re-aged at high crude oil saturation between floods. Numerous core floods with different rock types showed significant decrease in residual oil saturation from one flood to the next (Loahardjo et al. 2010a). Systematic decrease in residual oil saturation by sequential waterflooding was confirmed by nuclear magnetic resonance imaging measurements of in-situ saturations (Loahardjo et al. 2010b).In this work, sequential waterflooding has been demonstrated for outcrop Berea sandstones of medium and low permeability: both showed reduction in residual oil saturation with each sequential flood. The tests have been extended to include aging periods at either residual oil saturation or initial water saturation. Aging at residual oil saturation (high water saturation) resulted in an increase in oil recovery for the subsequent flood, with larger increases observed for extended aging times. After an extended period of aging at initial water saturation (high oil saturation), decreased oil recovery was observed. The variations in oil recovery are consistent with changes in wettability that depend on oil saturation during displacement and subsequent aging conditions.

One of the common challenges of applying foam for enhanced oil recovery is the foam instability in the presence of crude oil and nonwater-wet surfaces. In this experimental study, we systematically distinguish the effect of rock surface wettability from that of crude oil saturation on foam rheology under reservoir conditions. Neutral-wet Berea and reservoir sandstone cores are prepared by aging with crude oil, followed by the wettability index measurements. Transient foam generation and steady-state foam quality scans are conducted in neutral-wet cores, with/without water-flood residual oil. Nuclear magnetic resonance imaging is also utilized to measure the remaining oil saturation at the end of the foam-flood. It is shown that strong foam can be generated in a neutral-wet core with no residual oil because of the solubilization of the adsorbed crude oil components and the wettability alteration toward more water-wet conditions. However, in a neutral-wet core containing residual oil, foam generation is initially hindered. Foam generation occurs after injecting several pore volumes of surfactant solution and increasing the superficial velocity to overcome the minimum pressure gradient required for in situ foam generation. The findings from this study suggest that surface wettability in the presence of bulk oil saturation significantly affects transient foam generation. The final steady-state foam strength becomes comparable to the water-wet and oil-free case once the residual oil saturation is adequately reduced.

Nuclear magnetic resonance (NMR) T2 spin-spin relaxation is a well-established technique in petrophysics labs for quantifying bound/free water and pore-size distribution of reservoir rocks. The method has also been used to measure oil and water saturations, and to characterize wettability alterations for oil/water/rock systems. The T2 relaxation distribution measured by hydrogen NMR is the sum of contributions from both oil and water in the core. It is therefore necessary to separate the T2 signals of oil from water. Since deuterium oxide (D2O) does not have a NMR signal at the resonance frequency for hydrogen, brine made with D2O is commonly used as the aqueous phase to determine the oil saturation from NMR. The objective of this work was twofold: (1) to validate the oil saturations in the core with NMR T2 relaxation at connate water saturation (before and after aging) and residual oil saturation after waterflooding; and (2) to investigate the potential hydrogen-deuterium (H-D) ion exchange between rock minerals and D2O. Berea sandstone cores were used along with the crude oil from one of the fields in the Sarawak Basin, Malaysia. The aqueous phase was a synthetic brine made with either deionized water or D2O. Two cores containing the crude oil with D2O brine as the connate (or initial) water were aged at 75eC for up to 65 days. During the aging period, the cores were scanned three times for T2 measurements. The measured T2 volumes (supposedly a measure of the oil volume) of the two cores kept increasing as the aging time increased. However, mass balance indicated that the oil saturation was the same before and after aging. The inconsistent oil saturation measured by NMR indicated that there was H-D ion exchange between the rock minerals and D2O. The cores were then flooded with the fresh D2O brine, after which the residual oil from NMR agreed with that from mass balance, indicating that the fresh D2O had replaced the connate D2O brine affected by H-D ion exchange. Additionally, two cores fully saturated with D2O brine were also measured by NMR before and after aging at 75°C, again confirming the H-D ion exchange between the rock minerals and D2O. Finally, the mixture of the crude oil and D2O was measured by NMR before and after aging at 75°C, indicating that the interactions between the crude oil and D2O increased the T2 relaxation time. The total T2 volume was not affected. This work provides evidence of H-D ion exchange between rock minerals and D2O at elevated temperature. It is recommended that such interactions between the rock minerals and D2O brine be considered for related tests, especially when elevated temperature is involved.