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 ...
This paper introduces a comprehensive method on how to evaluate wetting properties and oil recovery potential by spontaneous imbibition of "smart water" into a low-permeable limestone reservoir (≈1 mD). The reservoir temperature was 110 °C, and the salinity of the formation water was high (∼208 000 ppm). Crude oils from different possible source rocks were characterized for acid and base numbers, asphaltene, viscosity, and density. The potential of water-based enhanced oil recovery (EOR) was evaluated on the basis of the following studies: (1) The wetting potential of crude oils toward carbonate surface was investigated. (2) The presence of capillary forces in the core material was tested by spontaneous imbibition.(3) The initial wetting condition was determined by the chromatographic wettability test on mildly cleaned cores. (4) The surface reactivity of limestone core toward Ca 2þ , Mg 2þ , and SO 4 2was evaluated, when exposed to seawater at different temperatures (70-150 °C). (5) The presence of anhydrite, CaSO 4 (s), in the limestone core material was confirmed, which will affect the initial wetting conditions. ( 6) The potential of "smart water" to enhance oil recovery from limestone cores containing crude oil and formation water at 110 °C was evaluated by imbibition of seawater and modified seawater. Because of the low content of acidic material in the crude oils and the presence of anhydrite in core material, the limestone cores were expected to be preferentially waterwet, which was confirmed by the chromatographic wettability test. About 40% of original oil in place (OOIP) was recovered in a spontaneous imbibition process at 110 °C using formation water. In a tertiary imbibition process with seawater and modified seawater, the oil recovery increased to ∼50% of OOIP.
Water-based enhanced oil recovery (EOR) from carbonates is usually restricted by initial wetting properties, especially in naturally fractured carbonates. Carboxylic material in the crude oil, quantified by the acid number (AN), is regarded as the most important wetting parameter. In this paper, it is shown experimentally that, for a given AN, the temperature and the amount of sulfate present in the formation water will affect the wetting condition significantly. The concentration of sulfate in the formation water is usually low because of a high amount of Ca2+, anhydrite, CaSO4(s), is precipitated at high temperatures. The interaction between small amounts of sulfate dissolved in the formation water and the rock surface was studied using chalk cores. The relative amount of sulfate dissolved in the pore water, SO4 2–(aq), and sulfate adsorbed onto the chalk surface, SO4 2–(ad), was quantified at different temperatures of 20, 50, 90, and 130 °C. Below 50 °C, the relative amount of SO4 2–(aq) and SO4 2–(ad) was quite constant, but above 50 °C, SO4 2–(aq) decreased, while SO4 2–(ad) was not significantly affected by increasing the temperature. Sulfate was precipitated as CaSO4(s) and retained in the core at 130 °C. Spontaneous imbibition of formation water, free from sulfate, was also conducted at 50 °C into mixed wet chalk cores, which were aged at different temperatures. When the aging temperature increased, the oil recovery by spontaneous imbibition decreased. Separate wettability tests also confirmed the increase in water-wetness as the aging temperature was lowered. The amount of sulfate present in the pore water, SO4 2–(aq), appeared to be the active sulfate species to increase the water-wetness, which was in line with the previously suggested mechanism for wettability alteration by seawater in carbonates. For the tested aging temperatures of 50, 90, and 130 °C, changes in wetting properties appeared to take place at sulfate concentrations in the formation water below 2 mmol/L. At higher concentrations of sulfate, the wetting properties were not significantly affected.
It is well accepted that seawater injection is able to improve the water wetness of carbonate reservoirs at high temperatures, and in that way, it can act as an enhanced oil recovery (EOR) fluid. A recent laboratory investigation showed that increased oil recovery also was obtained from carbonate reservoir cores by successively flooding composite limestone cores by 2, 10, and 20 times diluted seawater. The study confirmed that it is possible to obtain low salinity EOR effects also in carbonates, and not only in sandstones. In the present study, preserved reservoir core material from a similar limestone formation was used with the objective to obtain a chemical understanding of the mechanism for the improved oil recovery. It was verified, that the core material contained significant amounts of anhydrite (CaSO 4 ), which appeared to be the key factor for observing the low salinity EOR effect. The concentration of sulfate in the injection brine increased due to increased dissolution of anhydrite as the salinity and concentration of inactive salt, NaCl, decreased. Both an increase in the sulfate concentration and a decrease in NaCl content in the injected brine will have a positive effect on the wettability alteration process. An oil displacement test was conducted on a restored reservoir core at 100°C using 100 times diluted formation water in a tertiary flooding process, after first injecting formation water. This showed a low salinity EOR effect of 22% of original oil in place (OOIP), corresponding to an 88% increase in oil recovery. Also 30 times diluted seawater increased the oil recovery by 18% of OOIP in a tertiary flood after first flooding the core with formation water. After flooding a core successively at 100°C with formation water, seawater, and 10 times diluted seawater, the oil recovery increased gradually by 25, 30, and 33% of OOIP. The chemical low salinity EOR mechanism was discussed in terms of dissolution of anhydrite and a decrease in the NaCl concentration. This wettability alteration mechanism is, in principle, the same as that reported previously for injection of seawater and modified seawater into chalk cores, involving a symbiotic interaction between Ca 2+ , Mg 2+ , and SO 4 2− at the rock surface. In this case, supply of extra Ca 2+ and SO 4 2− was obtained by dissolution of anhydrite. The low salinity EOR technique can have a great economic potential regarding oil recovery from high temperature carbonate reservoirs containing significant amounts of dissolvable anhydrite distributed in the pore space.
Water based oil recovery from carbonates is a great challenge due to unfavorable wetting properties. Especially in naturally fractured formations, when spontaneous imbibition is an important drive mechanism, the oil recovery is low. In the past decade, much scientific work has been published focusing on the chemical understanding of wetting properties in chalk and limestone. Very little systematic work has been addressed to dolomite, which is also an important reservoir rock in the carbonate family. Recent work has shown that seawater acts as a Smart Water wettability modifier in calcite at higher temperatures due to symbiotic interaction between Ca2+, Mg2+, and SO4 2– and the rock surface. In the present work, the affinity of these active components toward the dolomite surface is discussed and compared to previous experimental work in calcite. The affinity of sulfate toward the carbonate surface, which is the catalyst for the wettability alteration process, was very low toward dolomite. Spontaneous imbibition studies confirmed that seawater was not a good wettability modifier in dolomite at 70 °C. Using 10 times diluted seawater as imbibing brine increased oil recovery due to wettability alteration by 15% of OOIP compared to ordinary seawater. No extra oil was recovered by using 100 times diluted formation water without sulfate as imbibing fluid, confirming that the low salinity brine must contain some sulfate as catalyst to achieve wettability alteration.
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