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Seawater can improve the water wetness of chalk at high temperatures, which improves the oil displacement by spontaneous imbibition of water. It is experimentally verified that the interaction between Ca 2þ , Mg 2þ , and SO 4 2at the chalk surface will displace adsorbed carboxylic acids and increase the water wetness. In this work, the effect of salinity and ionic composition of smart water on oil recovery was studied at different temperatures, 100, 110, and 120 °C. The ultimate oil recovery was compared using seawater as the base fluid. When NaCl was removed from seawater, both the imbibition rate and oil recovery increased in comparison to seawater at the temperatures tested. At 110 and 120 °C, the oil recovery from seawater depleted in NaCl increased by about 10% of original oil in place (OOIP) compared to seawater. A decrease in oil recovery of about 5% of OOIP was observed when increasing the amount of NaCl in seawater 4 times. A systematic decrease in oil recovery was observed when using seawater diluted with distilled water as imbibing fluid. Imbibition tests at 110 °C showed that the water-wet fraction increased 29% for seawater depleted in NaCl compared to 11% for ordinary seawater. Diluted seawater to 10 000 ppm did not change wetting conditions at 110 °C. The results confirmed that not only is the concentration of the active ions Ca 2þ , Mg 2þ , and SO 4 2important for wettability alteration to take place but also the amount of nonactive salt, such as NaCl, has an impact on the wettability alteration process, which is discussed as a doublelayer effect at the chalk surface. No significant improvement in the ultimate oil recovery was observed during forced displacement by modified seawater.

Waterflooding has for a long time been regarded as a secondary oil recovery method. In the recent years, extensive research on crude oil, brine, and rock systems has documented that the composition of the injected water can change wetting properties of the reservoir during a waterflood in a favorable way to improve oil recovery. Thus, injection of "smart water" with a correct composition and salinity can act as a tertiary recovery method. Economically, it is, however, important to perform a waterflood at an optimum condition in a secondary process. Examples of smart water injection in carbonates and sandstones are: (1) injection of seawater into high temperature chalk reservoirs and (2) low salinity floods in sandstone reservoirs. The chemical mechanism behind the wettability alteration promoted by the injected water has been a topic for discussion both in carbonates and especially in sandstones. In this paper, the suggested mechanisms for the wettability modification in the two types of reservoir rocks are shortly reviewed with a special focus on chemical similarities and differences. The different chemical bonding mechanisms of polar components from the crude oil onto the positively charged carbonate and the negatively charged quartz/ clay indicates a different chemical mechanism for wettability modification by smart water in the two cases.

Low-salinity enhanced oil recovery (EOR) effects have for a long time been associated with sandstone reservoirs containing clay minerals. Recently, a laboratory study showing low-salinity EOR effects from composite carbonate core material was reported. In the present paper, the results of oil recovery by low-salinity water flooding from core material sampled from the aqueous zone of a limestone reservoir are reported. Tertiary low-salinity effects, 2−5% of original oil in place (OOIP), were observed by first flooding the cores with high-saline formation water (208 940 ppm) and then with 100× diluted formation water or 10× diluted Gulf seawater at 110°C. It was verified by flooding the core material with distilled water that the core samples contained small amounts of anhydrite, CaSO 4 (s). The oil recovery was tested under forced displacement using different injection brines and oils with different acid numbers, 0.08, 0.34, and 0.70 mg of KOH/g. The low-salinity effect depended upon mixed wet conditions, and the effect increased as the acid number of the oil increased. No low-salinity effect was observed using a chalk core free from anhydrite. The chemical mechanism for the low-salinity effect is discussed, and in principle, it is similar to the wettability modification taking place by seawater described previously. In field developments, the oil reservoir is normally flooded with the most available water source. For offshore reservoirs, this means seawater or modified seawater. Thus, a relevant question addressed in this paper is can diluted seawater act as a low-saline EOR fluid after a secondary flood with seawater? Previous experiments have shown that both spontaneous imbibition and forced displacement tests using chalk cores, which were free from sulfate, did not show a low-salinity EOR effect when exposed to diluted seawater. This paper shows that, if anhydrite is present in the rock formation, diluted seawater or diluted produced water can act as an EOR injectant to improve recovery over that achieved with high-salinity brines. ■ INTRODUCTIONLarge carbonate oil reservoirs, in both the North Sea and the Middle East, are today flooded with seawater to achieve sufficient recovery to justify the substantial development costs. Seawater is used to maintain reservoir pressure and sweep oil to the producing wells. Historically, microscopic displacement efficiency has not been routinely optimized in the development stage. It is well-documented in the literature that laboratory studies show that seawater can modify the wetting condition in a favorable way to increase the oil recovery from hightemperature oil reservoirs, T res > 70−80°C. 1−4 The chemical mechanism for the increase in water wetness using seawater has been discussed, and the sulfate in seawater appeared to act as a catalyst for desorbing carboxylic material from the carbonate surface. 4 Recently, it has been shown that seawater can be modified to even act as a "smarter" enhanced oil recovery (EOR) fluid than ordinary seawater: (1) Seawater depleted in ...

The composition of the injecting brine has a profound effect on the efficiency of water-based enhanced oil recovery (EOR) methods. Recently, we observed that not only is the concentration of the active ions Ca 2+ , Mg 2+ , and SO 4 2À important for wettability alteration in carbonates but also the amount of non-active salt, NaCl, has an impact on the oil recovery process. Removing NaCl from the synthetic seawater improved the oil recovery by about 10% of original oil in place (OOIP) compared to ordinary seawater. The results were discussed in terms of electrical double-layer effects. In this work, we have modified the seawater depleted in NaCl by adjusting the concentration of active ions, Ca 2+ and SO 4 2À . Oil displacement studies in outcrop chalk samples by spontaneous imbibition were performed at temperature ranges of 70À120 °C using different oils and imbibing fluids. When the concentration of SO 4 2À in the seawater depleted in NaCl was increased 4 times, the ultimate oil recovery increased by about 5À18% of OOIP compared to the seawater depleted in NaCl. The amount of Ca 2+ in the seawater depleted in NaCl had no significant effect on the oil recovery at 100 °C, but significant improvements were observed at 120 °C. Chromatographic wettability analysis confirmed that the water-wet area of the rock surface increased as the oil recovery increased, emphasizing the importance of the ionic composition and the ion concentration of the injecting brine in the water-based EOR methods.