Abstract EOR by Smart Water injection in calcite, CaCO3, is dependent on factors like initial wetting, injection brine composition and temperature. Because of the chemical difference between CaCO3 and dolomite, CaMg(CO3)2, the relationship between EOR effects and the above-mentioned factors could be different. Smart Water EOR potential was experimentally tested for two dolomitic reservoir systems, at low and high reservoir temperature, to determine if there was a temperature limitation for observing EOR effects by Smart Water injection. Oil recovery tests by spontaneous and forced imbibition experiments were performed to evaluate initial wetting and wettability alteration from two dolomitic reservoir systems. A fractured reservoir system at 65 °C was investigated by spontaneous imbibition tests, while a non-fractured system at 115 °C was investigated by forced imbibition tests. The reservoir cores were saturated with their respective formation waters and crude oil, then imbibed with diluted seawater or modified seawater brines. Oil recovery responses at the different temperatures and by using different imbibing brines were evaluated and compared. Spontaneous imbibition tests, performed in the fractured reservoir system, showed that a diluted seawater brine increased the oil recovery from the dolomitic core material at 65 °C. When a modified seawater brine, which is a Smart Water for CaCO3, was used, there was no EOR effect observed. Forced imbibition tests with diluted seawater brine showed increased oil recovery for a non-fractured dolomitic reservoir system at 115 °C, while a modified seawater resulted in no extra oil produced. The results showed that there was no temperature limitation for observing EOR effects in dolomitic reservoir core material within the temperature range 65 - 115 °C. It was confirmed that diluted seawater brines altered the initial core wettability towards more water-wet conditions and enhanced oil recovery was observed both in spontaneous imbibition and forced imbibition experiments. Due to the differences in mineralogy between CaCO3 and dolomite, CaMg(CO3)2, and in their chemical reactivity, the optimal injection water, i.e. Smart Water compositions, were different. Smart Water EOR effects by wettability alteration in dolomitic reservoir material were observed both at low and high reservoir temperatures. The final oil recovery was dependent on the injection brine composition. Increased oil recovery was experienced in both spontaneous and forced imbibition tests.

Both laboratory studies and field observations have confirmed increased oil recovery by low salinity water injection beyond that obtained by standard water injection. Whether extra oil is produced or not depends on certain reservoir conditions, and among them is the content of clay minerals. Kaolinite clay minerals have been reported to impact the low salinity enhanced oil recovery (EOR) potential, and they are believed to be involved in the initial wetting of sandstone reservoirs. In this work, the effect of temperature on the wetting of clay surfaces was studied. The adsorption of the polar organic base, quinoline, onto kaolinite clay minerals was investigated at ambient and high temperature (130 degrees C) versus pH. The experiments were performed using brines with different ionic compositions and salinities. A discussion of the effect of brine chemistry, pH, and temperature on quinoline adsorption was also included. Finally, wettability alteration processes by adsorption and desorption of polar organic molecules were used to explain the low salinity EOR effect observed in clay containing sandstone reservoirs. The experimental results showed that the adsorption of quinoline onto kaolinite clay minerals was strongly dependent on pH at both ambient and at 130 degrees C. However, the adsorption at high temperature was reduced, which could affect the initial wetting of a sandstone reservoir system. The adsorption process was reversible by adjusting pH, and adsorption of quinoline was in general higher in a low salinity brine than in a high salinity brine. Thus, releasing basic polar crude oil components like quinoline from the kaolinite clay surface requires an increase in the brine pH, and not only a lowering of the salinity of the injection brine.

Previously reported experimental work has shown positive oil recovery effects by combining low salinity brine with polymer for injection into sandstone cores. The extra oil recovered by the combination of the two EOR methods was termed a "Hybrid EOR effect". The experimental work performed in the present study assessed the potential of combining low salinity (LS) Smart Water injection with polymer (P) flooding; LSP flooding. Dramatic improvements in the EOR effect were observed when combining LS in secondary mode with polymer injection in tertiary mode. Secondary LS injection gave 59 % OOIP after 1 PV injected, which is an outstanding result compared to secondary formation water (FW) injection reaching only 35 % OOIP after 1 PV, and an ultimate recovery of 40 % OOIP after 2.5 PV. The ultimate recovery with seawater (SW) in secondary mode was 44% OOIP, showing only a slightly better performance than FW, but poorer efficiency than the ultimate LS brine recovery of 64 % OOIP. In comparison, the ultimate recovery with secondary LSP injection was 66 % OOIP. The displacement front was stable and fast, but it did not give a substantial increase in oil recovery in comparison to the secondary LS injection. Tertiary LSP injection after secondary LS injection gave the highest oil recoveries with a total hybrid EOR effect of 86 % OOIP. All tertiary LSP floods gave improved displacement stability with EOR effects of similar to 20 % OOIP. The positive EOR effects are a result of redistribution of oil within the pore space after wettability alteration with the Smart Water. Oil attached to the mineral surface has low mobility, but at more water-wet conditions a new fraction of mobile oil, which is more easily mobilized with a polymer solution, is created (Wang et al., 2001). The combination of Smart Water with polymer flooding appears to have a huge potential for future EOR applications. Field development strategies for new sandstone reservoirs should include wettability alteration and redistribution of oil within the pores by Smart Water and improved displacement efficiency with polymer for optimized EOR to lowest cost.

Abstract Many offshore reservoirs have been seawater-flooded, which could affect the low salinity EOR potential. This paper evaluates the low salinity EOR potential after seawater flooding for a high temperature (148 °C), high salinity (~170000 ppm) sandstone reservoir. Secondary oil recovery by low salinity injection is compared to secondary seawater and tertiary low salinity water injection. Oil recovery experiments were performed at reservoir temperature using preserved reservoir cores. To mimic initial wetting conditions of the original oil reservoir, the cores were mildly cleaned and restored with the formation water and reservoir crude oil. Secondary seawater injection was performed, as well as secondary and tertiary low salinity water injection. Solid-brine surface reactivity tests were performed to evaluate chemical interactions, initial wetting, and potential for wettability alteration in the reservoir system. The pH of the first produced water in the oil recovery tests indicated favorable initial wetting conditions, i.e. mixed wettability, which is necessary for obtaining low salinity EOR effects by wettability alteration. However, the oil recovery tests showed no tertiary low salinity EOR effects after seawater flooding. Secondary low salinity injection resulted in 6-10% higher oil recovery compared to that obtained by secondary seawater injection. Low salinity injection normally generates cation exchange on the pore mineral surface promoting a pH increase and good conditions for observing wettability alteration. The produced water sample pH show that unfavorable Crude Oil-Brine-Rock interactions reduced the pH increment and the low salinity EOR potential after seawater injection. The surface reactivity tests also confirmed higher EOR potential by secondary low salinity injection, seen by a higher pH increase, which during low salinity injection triggers wettability alteration of the rock surface towards more water-wet, thereby recovering more oil. The results show that low salinity injection into a seawater-flooded reservoir is likely to be less efficient due to unfavorable chemical interactions and reduced pH increase, and therefore there is a reduced potential for wettability alteration. However, for this high temperature and high salinity reservoir secondary low salinity water injection could be an efficient EOR method.

Smart Water injection is an EOR technique that is both environmentally friendly and easily implementable to a fractional cost compared to other water-based EOR methods. EOR by Smart Water is a wettability alteration process towards more water-wet conditions, which induces increased positive capillary forces and increased microscopic sweep efficiency. The objective of this work was to evaluate the injection strategy for Smart Water in an offshore high temperature sandstone reservoir, and compare the efficiency of seawater-based injection brines with low salinity brines, which can behave as Smart Water in sandstone reservoirs. Oil recovery experiments have been performed at reservoir conditions using preserved reservoir cores and reservoir fluids. Secondary low salinity injection gave an average of 33.5 %OOIP extra oil produced, compared to modified seawater injection. The tertiary low salinity EOR effect after modified seawater flooding gave an average of 11.8 %OOIP extra oil. Significant changes in produced water pH from initially acidic to alkaline conditions during low salinity injection were observed, favoring wettability alteration towards more water-wet conditions. The results confirmed that low salinity brine behaved as a Smart Water, contributing with significant extra oil recovery in a high temperature sandstone reservoir. Introducing Smart Water from day one in a reservoir, i.e. in secondary recovery mode, is significantly more efficient, regarding both response time and ultimate oil recovery, than tertiary mode Smart Water injection.

At low oil price, using expensive chemicals in EOR methods is not economically feasible. Injecting water of a tailored composition, i. e. Smart Water, is thus a better option. It has previously been shown that injecting a brine of low salinity (LS), very often results in an increased oil production. In laboratory experiments it has been found that an “in situ” induced pH increase is a key parameter to experiencing a LS EOR effect in sandstones. In a field situation, e.g. Endicott, this pH increase is rarely observed, due to pH buffering by fluids, minerals and sour gases. When a LS injection brine is introduced into a core containing crude oil and high salinity (HS) formation water, desorption of cations from the mineral surface, and a subsequent adsorption of protons, H , leaves OH-, which increases pH. At high OH- concentrations, the acidic and basic polar organic molecules attached to the mineral surface transform into species of lower affinity to the mineral surface, and are released, leading to increased oil recovery. However, the different minerals present in sandstone can influence the induced pH increase. A pH screening test has been developed to investigate the minerals’ influence on pH. Clays are the main wetting materials in sandstone rocks, and they are also known to be cation exchangers, which can influence pH in the system. Feldspars have also been shown to influence pH in both a positive and a negative way, the latter responsible for the poor LS effect in the Snorre field on the NCS. A mineral often present in reservoir rock, but usually ignored, is anhydrite, CaSO4. In this paper the LS EOR potential in reservoir sandstone containing anhydrite and significant clay content was tested. Because of the amount of clays, this reservoir should be a good candidate for LS injection. The LS EOR potential was investigated using the pH screening test, oil recovery tests and chemical analyses. The main results from this study showed that reservoir core material containing anhydrite experienced poor LS EOR effects. When LS brine is injected into a reservoir containing anhydrite, some of the anhydrite dissolves and prevents parts of the cation desorption from the clay surface, thereby lowering the pH increase needed to observe increased oil recovery. Based on this study, other minerals than clays, such as anhydrite, can have a serious influence on the reservoir LS EOR potential, and should not be overlooked.

Injection of a Smart Water, with a modified and optimized ionic composition, is an environmentally friendly and cheap enhanced oil recovery (EOR) method. To be able to optimize the ionic composition to cause wettability alteration in the reservoir, one must understand the initial wetting of the reservoir. Experimental studies have confirmed that acidic material in the crude oil, especially negatively charged carboxylates, R-COO-, are the most important wetting parameters toward positively charged carbonate surfaces that dictate the rock wettability. The carboxylate molecules bond strongly to the carbonate surface, and these crude oil anchor molecules can only be removed from the calcite surface by chemical reactions. Generating representative core wettability during core restoration in the laboratory is important for doing realistic oil recovery studies, capillary pressure and relative permeability measurements. Water-wet outcrop chalk cores showing good reproducibility were used to study adsorption of carboxylic material onto chalk. Crude oil with a known acid number (AN) was flooded in different quantities through water-wet chalk cores containing 10% formation water saturation. The core wetting was evaluated by spontaneous imbibition tests, forced imbibition tests, and chromatographic wettability tests. The results of the work showed that the core wetting was determined by the amount of crude oil flooded through the core. The one core that had seen only 5 pore volumes (PV) of crude oil behaved much more water-wet than the core that had seen 15 PV of the same crude oil. Oil recovery by spontaneous imbibition was both lower and slower from the core that had seen the most oil, owing to the difference in wetting and capillary forces. With forced imbibition, viscous forces were introduced and the oil recovery immediately increased in both cores. The increase in oil recovery from the most water-wet core was larger than that of the less water-wet core, despite the residual oil saturation and, consequently, the EOR potential being lower in the most water-wet core. This suggested that the capillary forces not only influenced the spontaneous imbibition but also the forced imbibition, leading to a difference in recovery, which was related to a difference in wetting.

Experimentally, it has been found that Ca2+ and SO42– are key ions in the Smart Water wettability alteration process in limestone and that low-salinity (LS) enhanced oil recovery (EOR) effects in limestone can be observed if the formation minerals also include dissolvable anhydrite, CaSO4. A diluted brine, such as a standard LS brine, contains low amounts of Ca2+ and SO42–, which prevent wettability alteration from taking place. However, if the formation contains anhydrite mineral, Ca2+ and SO42– are supplied to the injection brine through dissolution, and in that case, a standard LS brine can cause wettability alteration in a limestone reservoir. A tertiary LS EOR effect of 22% original oil in place was observed at 100 °C during viscous flooding of 100 times diluted formation water in a limestone reservoir core containing anhydrite. Anhydrite dissolution and precipitation is dependent upon the temperature, and the solubility of anhydrite in water decreases as the temperature increases. In this paper, the...

Injection of a Smart Water, with a modified and optimized ionic composition, is an environmentally friendly and cheap EOR method. To be able to optimize the ionic composition to cause wettability alteration in the reservoir, one must understand the initial wetting of the reservoir. Experimental studies have confirmed that acidic material in the crude oil, especially negatively charged carboxylates, R-COO-, are the most important wetting parameters towards positively charged carbonate surfaces that dictate the rock wettability. The carboxylate molecules bond strongly to the carbonate surface and these crude oil anchor molecules can only be removed from the calcite surface by chemical reactions. Generating representative core wettability during core restoration in the laboratory is important for doing realistic oil recovery studies, capillary pressure and relative permeability measurements. Very water-wet outcrop chalk cores showing good reproducibility were used to study adsorption of carboxylic material onto chalk. Crude oil with a known acid number (AN) was flooded through water-wet chalk cores with 10 % water saturation. The AN of the eluted oil was measured and the amount of adsorbed acidic organic material was determined. It is a general assumption that aging of a core is a requirement to generate a mixed-wet core. Therefore the wettabilities of aged and non-aged cores were determined and compared by spontaneous imbibition and chromatographic wettability tests. The results of this study first and foremost showed that both the aged and non-aged core behaved mixed-wet, thus aging is not a requirement to generate a mixed-wet core. The two parallel cores adsorbed similar amounts of acidic material, and the chromatographic wettability test results showed similar water-wet surface area in both the aged and non-aged cores. However, since spontaneous imbibition is very sensitive to the location of the oil-wet surface, a difference in capillary forces between the aged and non-aged cores was observed. The non-aged core behaved mixed-wet in a spontaneous imbibition test, while the aged core behaved slightly less water-wet than the non-aged core. It seems that during the aging process the oil components were distributed in such a way to influence the capillary forces to some degree. To conclude, aging is not necessary to change the wettability of an initially water-wet core that has been flooded with crude oil. The acidic polar oil components attach to the carbonate surface immediately upon contact, resulting in a mixed-wet system.

Previous experimental work has indicated that the induced increase in pH as the high salinity formation brine is displaced by low salinity brine, is a key factor for observing low salinity EOR effects. The pH gradient is mainly due to desorption of Ca2+ from the clay surface in the presence of low salinity brine depleted in Ca2+. Desorption of Ca2+ from the clay surface is an exothermic process, which decreases the pH gradient as the temperature is increased. Therefore, a decrease in the low salinity EOR effect at high temperatures is observed. Some types of reactive plagioclase, especially albite, may also influence the pH as the brine salinity is changed. The exchange of Na+ with H+ is less temperature sensitive.Tertiary low salinity EOR effects from outcrop core material containing both clay, approximate to 10 wt%, and reactive albite, approximate to 30 wt%, have been studied at 60 and 120 degrees C. The low salinity EOR effects at the two temperatures were quite similar, 9.2 and 8.7% of OOIP, respectively. The oil recovery test results agreed well with the observed pH gradients for the oil-free core material, which were also quite similar, 2.3 and 2.2 pH units at 60 and 120 degrees C. The oil recovery and pH screening results showed that ion exchange at the albite surface will partly compensate for the decreased ion exchange at the clay surface at higher temperatures. Therefore, the presence of reactive plagioclase in high temperature sandstone reservoirs seems to be favorable for observing LS EOR effects provided the initial pH of formation water is low enough to make the rock mixed wet.

Core material, whether outcrop or reservoir core material, is prepared in the laboratory to mimic reservoir conditions. For carbonate reservoirs, the initial water saturation, Swi, is usually established by using either the porous plate technique or the desiccator method. The core is then flooded with crude oil and carboxylic material, R-COO−, quantified as acid number, AN, adsorbs onto the carbonate surface and acts as anchor molecules towards the crude oil in the wetting process. The correct reservoir wetting equilibrium is obtained when the AN of the crude oil in the pores is the same as the AN in the original reservoir crude oil. The focus of this paper is to determine the volume of oil a core must be exposed to in order to achieve equilibrium in the wetting process. The volume needed to reach equilibrium in the wetting process was tested by flooding outcrop core material at Swi=0.10 with crude oil, AN=0.35 mgKOH/g, and measuring the change in AN at the core outlet. The tests were performed at three different temperatures, 50, 90, and 130°C, and the flooding rate was constant, 4 PV/D. The test at 50°C and 90°C showed a similar response, where the test at 130°C clearly required a lower volume of oil to establish equilibrium. A chromatographic wettability test also showed that the water wet fraction of the surface area decreased for the test at 130°C. A new core was retested at 50°C and restored by mild cleaning using kerosene and heptane. The restored material required an even lower volume of oil to establish the wetting equilibrium, and the water-wet area was reduced. Thus, outcrop carbonate core material needed longer exposure time to crude oil to achieve wetting equilibrium compared to that of restored core material previously exposed to the same crude oil. Furthermore, the core became even more oil-wet after restoration.

Restoration of carbonate reservoir core material for special core analysis has been debated in the literature for some time. An important goal of core restoration is to reproduce initial reservoir wetting properties because wettability dictates important reservoir parameters, such as capillary pressure and relative permeability of oil and water. It has previously been found that acidic polar components in crude oil dictate the wetting properties in carbonate core material. In this paper, the effects on chalk wettability from crude oil flooding, core aging, and mild core cleaning were investigated experimentally. The experimental results confirmed that adsorption of acidic polar components is an instantaneous process and that a dynamic equilibrium was achieved with a specific adsorption capacity of the initially very water-wet chalk surface. The crude oil flooding reduced the water wet surface area. Core aging for 2 weeks at the test temperature reduced the water-wet surface area even further, which appeared to be closer to a thermodynamic equilibrium. Spontaneous imbibition tests confirmed mixed-wet conditions, regardless of aging or not. A second oil flooding was performed on a mildly cleaned, initially mixed-wet chalk core. The dynamic adsorption equilibrium of polar organic components was now drastically reduced. On the basis of the results from this experimental study, the wetting in outcrop chalk is dependent upon the amount of crude oil allowed to contact the rock surface and the time period of contact, i.e., the aging period. A core restoration procedure involving mild core cleaning and a controlled small volume of crude oil injection could be a more optimal core restoration procedure for reservoir chalk and limestone cores.

Despite it more than 500 papers being published on low-salinity (LS) water injection into sandstone oil reservoirs to enhance oil recovery, very few field applications of this enhanced oil recovery (EOR) technique are known. Laboratory investigations of LS water floods under tertiary conditions have shown varying results, and especially, the response time for establishing a new bank of oil in the porous-medium has been too slow for application in the field. Usually, many pore volumes (PVs) of LS brine must be injected to obtain an increase in recovery of 5-10% of original oil in place (OOIP). Provided that the initial reservoir conditions for observing LS EOR effects are present, a close connection between the imposed pH gradient and additional oil recovery has been, experimentally verified. To improve the chemical understanding of the LS EOR mechanism; it appeared important to study the development of the pH gradient because the HS brine is displaced by the LS brine. Therefore, the relationship: between the LS EOR effect, pH gradient development, and heterogeneity in the pore size distribution of the porous medium was addressed in this paper. The-experimental-Work covered both tertiary and secondary LS core flooding. The outcrop core material used had consistent composition and contained 8.2 Wt % illite and 32.0 wt % albite, which both can contribute to the pH gradient under LS flooding conditions. In comparison to secondary oil recovery by injection of formation water (FW), similar to-40% of OOIP, the secondary oil recovery using LS brine produced an additional 24% of OOIP. Tertiary injection of LS brine increased the recovery by about 10% of OOIP, after:a secondary flood by FW. Injection of a tertiary low-salinity polymer (LSP) Solution after secondary flooding With LS brine increased the ultimate recovery from 65 to about 86% of OOIP. In both cases, the response time for the LS EOR effect was discussed in terms of imposed pH gradient and heterogeneity in the pore size distribution. The results showed that Oil-recovery Was closely linked to an increasing pH gradient. The response time to develop the pH gradient and a new bank of oil that could be produced seemed to be related to the pore size distribution; i.e., it took a longer time to develop a pH gradient and to displace the from the smaller pores than-from the larger pores.

Abstract Low salinity water injection in sandstone is an emerging technology just on the verge of being implemented full field in the UK and in Alaska, USA. Laboratory studies are important for providing relevant and well interpreted data before performing the field trial. However, laboratory investigations show varying results on low salinity EOR, most probably because of a limited understanding of the nature of the process. Recently we have published a "Smart Water" EOR mechanism where pH changes at the rock surface is inducing the wettability alteration, improving positive capillary forces and microscopic sweep efficiency. Researchers have experienced rather poor low salinity EOR effects from 17 different sandstone outcrops from the USA. In this work we have investigated 6 of the same 17 outcrops, and according to our chemical understanding, some factors are more important for observing LS EOR effects in sandstone. It is the increase in pH, ΔpH, obtained when the high salinity (HS) formation water is displaced by the low salinity (LS) injection water, and it is the initial pH and the amount of active cations (Ca2+) in the formation water that are related to the initial wetting. We have established a link between the poor low salinity EOR effect from all 6 outcrops and the corresponding pH change observed when switching from high salinity to low salinity injection water. The presence of different types of minerals such as clay, feldspars and anhydrite will influence the pH change, and must be taken into account. Additionally, we have seen that the formation water composition has strong influence on the low salinity EOR effect. Using a formation water with salinity like seawater (FW1 ~35 000 ppm) showed only a minor tertiary low salinity EOR effect, 0.74 %OOIP, corresponding to a low pH gradient of 0.5. While experiments using a high salinity formation water (FW2 ~100 000 ppm) showed a 5 % OOIP recovery, corresponding to a larger pH gradient of 2.0. The results observed are in agreement with the suggested chemical mechanism for the low salinity EOR effect, confirming that it is the pH gradient that triggers the low salinity EOR effect. In addition, the pH screening test used in this work proved once again to be a reliable tool to evaluate the low salinity EOR potential.

Water flooding of oil reservoirs has been, and still is, the most important technique to increase oil recovery from both carbonate and clastic oil reservoirs. Significant improvements in the general understanding of the wetting properties of oil reservoirs have been the fundament for a lot of research during the last 15–20 years with the objective to optimize the oil recovery by wettability modification. The ion composition of the injected water can modify the wetting properties of the porous rock during the production time, and improve the displacement of oil. Such an EOR technique is environmentally friendly, because no external chemicals are added, and significant extra oil amounting to 5–20%OOIP have been reported, both in the laboratory and in field pilots. Therefore, water based EOR by wettability modification has received great interest among oil companies and researchers. A large number of different mechanisms have been suggested for this EOR process. This paper is a chemical review of the EOR technique called Smart Water flooding, which also include aspects of low salinity flooding in clastic reservoirs. The review is divided into four main parts; (1) The most important wetting parameters for the different phases, oil, brine and rock, are presented, (2) The symbiotic interaction between the different wetting parameters on the initial wetting properties is discussed, (3) The chemical mechanism for observing “Smart Water” EOR effects at different initial wetting conditions is presented, and (4) The suggested chemical mechanism is verified by lab and field data.

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 SO42- 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 degrees 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.

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 (CaSO4), 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 degrees 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 degrees 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 Ca2+, Mg2+, and SO42- at the rock surface. In this case, supply of extra Ca2+ and SO42- 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.

The mechanism of the low-salinity (LS) enhanced oil recovery (EOR) process in sandstone reservoirs has been debated in the literature for more than a decade. We recently proposed a chemical wettability alteration mechanism for the process, well-founded in experimental observations. Even though the chemical understanding is quite well-described, there are parameters/factors that could influence the main process. Combinations of certain reservoir minerals, temperature, and salinity/composition of the formation water (FW) could have impact on the EOR process by affecting: (1) the initial wetting condition and (2) the wettability alteration process when the high-salinity (HS) FIAT is displaced by LS water. It has been experimentally observed that the LS EOR effect decreases as the reservoir temperature increases. This paper discusses the LS EOR effect related to oil recovery at high temperatures, T-res > 100 degrees C, and high FIAT salinities, similar to 200 000 ppm. In general, the adsorption of active organic polar components onto clay minerals decreases as the temperature and salinity of the FIAT increases. As a result, the rock becomes more water-wet, and the LS EOR potential is decreased. Oil recovery tests at 110 degrees C with HS FW of similar to 200 000 ppm did not show any LS EOR effects, with either seawater (SW) or 50 times diluted seawater (d(50)SW) as LS fluids. However, when the FW salinity was reduced to similar to 23 000 ppm, a LS EOR effect was observed. The combination of a high reservoir temperature and HS FW is most likely not favorable for observing LS EOR effects. The desorption of Ca2+ ions from the clay surface is reduced as a result of both dehydration at high temperature and the common ion effect by dissolution of CaSO4 if the formation contains anhydrite.

The Low Salinity Enhanced Oil Recovery effect in sandstone is promoted by a wettability alteration of clay surfaces towards more water-wet conditions. The key to understand the process is obtained through a detailed chemical understanding of rock fluid interaction at the clay surfaces. Based on our recently proposed chemical “Smart Water” mechanism, the pH is the main factor influencing the wettability alteration in Sandstone reservoirs. The increase in pH has been experimentally verified to be related to Ca2 desorption from clay surfaces due to the small concentration of Ca2 present in the “Smart water”. In this paper, desorption of divalent cations, Ca2 and Mg2 , from clay surfaces is studied. The experiments are performed under controlled conditions in a sand pack containing only kaolinite and quartz at different temperatures, room temperature and 130 oC. The retention of the active cations, Ca2 and Mg2 , was measured and compared with the non-adsorbing tracer; Li . The results show divalent cations display a high reactivity towards clay surface and that Ca2 by far is the most reactive species. The reactivity also increases with increasing temperature.

Originally, chalk reservoirs were waterflooded for pressure support; maintaining the pressure above the bubble point of the oil, and also preventing the compaction of the rock caused by the pressure depletion. Seawater waterflooding into a chalk reservoir in the North Sea proved to be a success not only by maintaining pressure and reducing compaction, but additionally the oil recovery rate soon increased. Intensive research during the last decade has proven that seawater at high temperatures acts as a “Smart Water” being able to improve the water wetness of carbonates. The reason for that are the chemical interactions happening in the reservoir between the oil, rock and injection water, disturbing the established chemical equilibrium and leaving the rock surface a little more water-wet. The increased water wetness generates positive capillary forces, and the microscopic sweep efficiency is increased. Recent research has shown that seawater can even be modified to improve the oil recovery in a spontaneous imbibition process by 10% compared to the recovery using ordinary seawater. The seawater composition has to be tailored for every specific reservoir system, and especially important parameters to consider, when deciding on the composition of the injected seawater, are the mineralogy of the reservoir rock, and the temperature of the reservoir. For high temperature chalk fields > 100 °C, like Ekofisk (130 °C), seawater depleted in NaCl should be used as the “Smart Water” EOR fluid. For lower temperature reservoirs, <100 °C, like Valhall (90 °C), either seawater spiked with sulfate or seawater depleted in NaCl and spiked with sulfate should be used as the “Smart Water” EOR fluid. In this study, the objective was to optimize the seawater-based “Smart Water” composition for injection into chalk/carbonate. The optimal amount of NaCl present in seawater was investigated at 90 °C. The experimental results showed that more than 90% of the NaCl needed to be removed from seawater in order to increase the oil recovery significantly, compared to the recovery using ordinary seawater. By doing so, the oil recovery increased by approximately 8% OOIP.