Composition on the Low-Salinity

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The influence of formation water salinity/composition on the low salinity EOR effect in high temperature sandstone reservoirs Zahra Aghaeifar, Skule Strand , Tor Austad, Tina Puntervold, Hakan Aksulu, Kine Navratil, Silje Storås, and Dagny Håmsø University of Stavanger, 4036 Stavanger, Norway

Abstract 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; (2) The wettability alteration process when the High Salinity (HS) FW 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, Tres>100 °C, and at high FW salinities, ~200 000 ppm. In general, the adsorption of active organic polar components onto clay minerals decreases as the temperature and salinity of the formation water increases. As a result, the rock becomes more water wet, and the LS EOR potential is decreased. Oil recovery tests at 110 °C with HS FW ~200 000 ppm did not show any LS EOR effects, either with seawater (SW) or 50 times diluted seawater (d50SW) as low salinity fluids. However, when the FW salinity was reduced to ~23 000 ppm, a LS EOR effect was observed. The combination of 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 due to both dehydration at high temperature and the common ion effect by dissolution of CaSO4 if the formation contains Anhydrite.

Introduction In recent papers, we have experimentally verified the importance of reservoir pH for the chemical understanding of the low salinity enhanced oil recovery mechanism in sandstone 1 ACS Paragon Plus Environment

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reservoirs.1-4 It is commonly accepted, that the rock must be mixed wet, and that clays, as the main wetting mineral, play an important role in the initial reservoir wettability, and the LS EOR effect. With a balanced adsorption of active cations (mainly Ca2+ and H+) and basic and/or acidic organic material in the crude oil onto the clay minerals, a wettability alteration towards more water-wet could induce a tertiary EOR effect when switching from a HS to a LS injection brine.3 The adsorption of basic and acidic organic material onto the negative sites on the clay surface dictates the initial rock wettability and depends on pH, temperature, ion composition, and salinity of the FW. The protonated form of the basic material, symbolized by R3NH+, and the non-dissociated carboxylic acid, RCOOH, appeared to be the most reactive organic species towards the negatively charged clay surface, meaning that the reservoir rock becomes less water-wet as the pH of the FW is decreased from ~7 to ~5. The basic material attached to the clay surface by electrostatic interactions. Adsorption of carboxylic material onto negatively charged clay take place by hydrogen bonding. 2, 4-6 Sour gases like CO2 and H2S present in the reservoir crude oil will partition into the FW and reduce initial reservoir pH, normally in the range of 5 - 6.5. In core systems with constant wetting, maximum oil recoveries during water injection are obtained at slightly water-wet conditions due to less capillary entrapment of oil.7 During Water injection with LS brines, the EOR effect is linked to increase in water wetness and improved microscopic sweep. The microscopic sweep efficiency is improved by spontaneous imbibition of the LS brine into previously bypassed pores of low water wetness. A new bank of mobile oil is then formed. When active cations like Ca2+ are desorbed from the clay surface as the HS FW is displaced by the LS brine, the free negative charged sites on the clay surface has to be balanced, to some extent by protons from the water. This create a local pH increase at the clay surface that promotes desorption of organic material due to ordinary acid-base reactions, Eqs. 1-3.2, 4 Slow reaction: Clay-Ca2+ + H2O ↔ Clay-H+ + Ca2+ + OH- + Heat

(1)

Fast reaction: Clay-R3NH+ + OH- ↔ Clay + R3N: + H2O

(2)

Fast reaction: Clay-RCOOH + OH-

(3)

↔ Clay + RCOO- + H2O

At high pH the adsorbed organic material is then transformed to their alkaline forms, i.e. R3N: and RCOO- which have much lower affinity towards the clay surface.5, 8 Proton transfer reactions are known to be very fast. Therefore, the rate determining step for observing the LS EOR effect is the desorption of active cations like Ca2+ from the clay surface. The Ca2+ desorption is an exothermic process. Ca2+ desorption decreases as the temperature increases, i. e. the Eq. 1. is moved to the left.1 Significant LS EOR effects requires a balanced adsorption of organic material, Ca2+ and H+ onto the clay surfaces. This can be obtained if: (1) The rock contains a significant amount of active clays (Illite and Kaolinite), preferentially more than 10 wt%. (2) The crude oil contains polar components, acidic and/or basic material, quantified by the acid number (AN) and base 2 ACS Paragon Plus Environment

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number (BN) in mg KOH/g. (3) The FW contains divalent cations, especially Ca2+. (4) The initial reservoir pH is less than 6.5 (pH 7, by driving Eq. 4 to the right. The adsorption of polar organic material will be reduced, and the rock surface will become too water wet for observing significant LS EOR effects.3 HS FW will move Eq. 4 to the left, i.e. preventing the exchange of Na+ by H+, and acidic conditions could be obtained, causing mixed wet conditions on the rock, which is favorable for LS EOR effects. When switching the flooding fluid from HS brine to LS brine both Eqs. 1 and 4 will contribute to increased alkalinity, which is needed for desorption of organic material.9 Without Plagioclase/Albite present, the pH gradient and also the LS EOR effect is mostly depending on Eq. 1. Eq. 1 will be influenced by the supply of Ca2+ ions to the water phase by dissolution of anhydrite, CaSO4 (s). The common ion effect will decrease the pH gradient by driving Eq. 1 toward the left. High temperature reservoirs preflooded with seawater may definitely contain precipitated anhydrite. Reservoirs at high temperatures will also decrease the pH gradient due to the exothermic nature of Eq. 1. Without initial mixed wet reservoir conditions, it is impossible to obtain wettability alteration and LS EOR effects. Surely, both the temperature and the type and amount of cations present in the formation water will affect the adsorption of organic polar material onto the clays and also the initial wetting condition. The objective of this work is to study the effect of formation water salinity/composition on the LS EOR effect at high reservoir temperatures, Tres= 110 °C, using three triplet preserved sandstone cores. First one core was flooded with FW, with a quite high salinity of ≈200 000 ppm, and there was no LS EOR effect when introducing neither seawater nor LS brine. In another core a low salinity FW, ≈23 000 ppm, was used, and in this case, a LS EOR effect was only observed after introducing the LS brine. In addition, the influence of certain minerals present in the core material, like anhydrite, on the pH gradient and the LS EOR effect at reservoir temperature was also investigated. And finally, to confirm that initial adsorption of polar oil components onto the clay surface is a function of the FW salinity and reservoir temperature, static adsorption of a model basic component onto Illite clay was done using different brine salinities at both room and high temperature. The results were in line

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with those observed in real core material, that high FW salinity and high temperature resulted in a less oil-wet wetting condition.

Experimental Core material Four preserved sandstone reservoir cores, RC1, RC3a, RC3b, and RC3c, containing about 20 wt% clay, mostly Illite and Kaolinite, were used. The cores RC3a, RC3b and RC3c were triplet cores, i.e. they were sampled close together from the same reservoir zone and are assumed to have similar physical and chemical properties. Core properties are listed in Table 1.

Clay mineral Illite clay was sampled from the Rochester formation in New York and delivered by Ward’s Natural Science Establishment in the form of green shale containing about 85 wt% Illite. The shale was crushed and wet milled in Methanol with a planetary ball mill to a powder with particle sizes less than ~2 µm. The milled Illite clay was cleaned and protonated to remove dissolvable salt and possible divalent cations from the clay surface by stirring in deionized (DI) water at pH 3 until a stable pH was obtained. The suspension was then centrifuged and flushed with DI water until stable pH of ~5 was reached. Then the clay was dried at 90 °C.

Brines Synthetic brines were used in the tests. The brines were made by dissolving desired amount of salts in DI water. For the oil recovery tests, the formation waters termed FW1 and FW2 were used. In addition Seawater (SW), and 50 times diluted SW, d50SW, were used as injection brines. The brine compositions are given in Table 2. For the surface reactivity test, the brines termed: HS1 and LS1 were used. Compositions are given in Table 3. For the static adsorption tests of Quinoline onto Illite, the brines termed: HS2, LS2, CaCl2, and FW3 were used. Compositions are given in Table 4.

Crude Oil A stabilized reservoir crude oil was used in the experiments. Physical and chemical properties with acid and base numbers as listed in Table 5. The crude oil was transferred to a recombination cell, and saturated with CO2 at 6 bar and ambient temperature. All oil recovery experiments were conducted with a back pressure of 10 bar to avoid two phase flow with oil and gas.

Core cleaning The preserved reservoir cores were mildly cleaned. First the core was flooded with Kerosene to displace initial crude oil until the effluent was colorless, followed by heptane to displace the kerosene. Then the core was flooded only a few PV with 1000 ppm NaCl brine to displace FW and dissolvable salts. At the end the core was dried at 90 °C until constant weight.


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Depletion of anhydrite The mildly cleaned cores RC3b and RC3c were depleted in Anhydrite minerals by flooding with 1000 ppm NaCl brine at a rate of 4 PV/D. Dissolved sulfate in effluent samples was monitored, and the depletion process was stopped when the sulfate concentration was less than 0.1 mM.

Core Restoration The mildly cleaned and dried cores RC3a, RC3b, and RC3c were restored for oil recovery tests. Initial water saturation of 20% was established using the desiccator technique.11 The core was mounted in a Hassler core holder with a confining pressure of 20 bar and with a back pressure of 10 bar. It was evacuated for a short time down to the vapor pressure of water and saturated with crude oil containing CO2. The core was then flooded with the same crude oil, two pore volumes (2 PV) in each direction at reservoir temperature. Finally, the core was aged in the core holder at reservoir temperature, 110 °C, for 14 days.

Oil recovery tests The oil recovery tests were performed at reservoir temperature, 110 °C. Core RC3a and core RC3b was successively flooded with FW1 – SW – d50SW. The core RC3c was flooded with FW2 – SW – d50SW. The flooding rate in all recovery tests was 4PV/D. Volume of produced oil was recorded at ambient conditions. Volumes of produced oil were compensated for temperature, pressure and gas shrinkage. In addition, the pH, density and ion concentration of produced water samples were analyzed.

Core surface reactivity test A mildly cleaned core RC1 was used in a surface reactivity test. The core was 100 % saturated with HS1 brine in a core holder and aged over night at the actual test temperature. The core was successively flooded with HS1 – LS1 – HS1 at a rate of 4 PV/D with a back pressure of 10 bar. The core was flooded until the pH in effluent samples was stable, before switching to the next brine. Chemical analyses of effluent samples were performed and the ion concentration of Ca2+ and SO42- recorded. The test was performed at three different temperatures; 40, 90, and 130 °C.

Quinoline adsorption onto Illite Clay An adsorption study of Quinoline onto Illite clay was performed in brine suspension. Different brine suspensions containing 0.01 mM Quinoline and 10 wt% Illite clay were used. The experiments were performed at different pH, 5, 8 and 5 again, by adding very small volumes of concentrated HCl or NaOH to the suspensions. The samples were equilibrated and stirred for 24 hours, centrifuged, and Quinoline concentration in the aqueous phase was analyzed. The amount of adsorbed Quinoline could then be calculated by mass balance. The Adsorption studies were performed at both ambient temperature and 130 °C. For each brine, table 4, three parallel tests were performed.


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Chemical analysis Produced water samples were diluted and analyzed using a Dionex ICS-3000 Ion Chromatograph. The ion concentrations were calculated based on external standard method. The repeatability of Ca2+ and SO42- analyzes was tested and found better than 2%. The pH was measured on fresh effluent samples using a Mettler EasySeven pH-meter. The amount of Quinoline was quantified by using a Shimandzu UV-1700 spectrophotometer. Linear calibration curves for Quinoline in all brines were obtained by adjusting the sample pH to ~3 and measuring the absorbance at wavelength 312.5 nm. The repeatability of Quinoline analyzes was tested and found better than 3%.

Results and discussion The cores RC3a, RC3b and RC3c were triplet cores, and used in oil recovery tests. The high saline formation water (FW1: ≈200 000 ppm; containing 640 mM Ca2+) was used in the experiments with RC3a and RC3b. The low saline formation water (FW2: ≈22 000 ppm; containing 8.9 mM Ca2+) was used in the oil recovery test from core RC3c. The reservoir temperature in all experiments was 110 °C.

LS EOR effect at high Tres and high salinity of FW The reservoir core RC3a was successively flooded with FW1 – SW – d50SW at 110 °C, Fig. 1. No increased oil recovery was observed during neither SW injection nor d50SW injection, after the core initially was flooded with the high salinity formation brine, FW1. The ultimate oil recovery remained at about 65% of OOIP. The pH of the eluted FW1 was below pH 6, Fig. 2, which should be low enough to promote initial adsorption of polar components onto the clay surface.4, 6 When switching from FW1 to SW, the pH of the produced water increased less than 1 pH unit. The presence of CO2 in the crude oil will have a buffering effect and lower the increase in pH. The pH increased to slightly above 7 when the low saline water d50SW was injected, but no LS EOR effect was detected. The displacement of oil by FW1 appeared to be very piston like, i.e. no significant amount of oil was recovered after the water breakthrough, which is an indication of very water wet condition. In general, the adsorption of strongly hydrated Ca2+-ions onto clay minerals will increase as the temperature increases due to the dehydration of Ca2+. An increase in Ca2+ adsorption onto the negative sites on the clay surface will reduce the adsorption of polar organic material from the crude oil. In this case with high salinity FW, the initial rock wettability appeared too water wet for observing LS EOR effects. High temperature oil reservoirs with high salinity formation water and large amount of Ca2+ ions may contain precipitated anhydrite, CaSO4(s), as part of the initial rock minerals. Furthermore, SW flooding of high temperature oil reservoirs could also cause precipitation of anhydrite. Therefore, the produced water during the oil recovery test on core RC3a was analyzed for Ca2+ and SO42-. Initially, FW1 did not contain any SO42-, but as shown in Fig. 3, sulfate was present in the effluent even though the formation water contained a very high concentration of 6 ACS Paragon Plus Environment

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Ca2+. The sulfate concentration decreased from 4 to 2 mM during the FW1 flooding. The concentration of SO42- in d50SW was 0.48 mM, but the concentration in the effluent ended at about 3 mM, i.e. the concentration was increased by a factor of 6. This is a strong indication that dissolvable anhydrite must be present in the formation since the concentration of Ca2+ and SO42- became quite similar. As pointed out in the introduction, increased dissolution of anhydrite in the presence of the LS fluid will move Eq. 1 to the left due to the common ion effect and reduce the increase in pH. The influence of anhydrite on the pH gradient has been therefore evaluated by exposing the core RC1 for a HS - LS water flood at different temperatures1. Surface reactivity test The pH response, when flooding a cleaned and 100% water saturated core with HS and LS brine at actual temperatures, will give valuable information about how the reservoir minerals responded to the injected brines without taking into account buffering effects from the crude oil. In order to detect possible effects of anhydrite present in the core, the brines HS1, containing only NaCl and CaCl2 (~100 000 ppm) and LS1, containing only NaCl (1000 ppm), were used, Table 3. The test was performed on core RC1 in the order of increasing temperatures by flooding the core successively with HS1-LS1-HS1. At all temperatures, the effluent pH with HS1 was close to 7, Fig. 41. In the first test at 40 °C, the increase in pH was surprisingly small, about 0.5 pH units. In the next test at 90 °C, the pH increased slowly up to 9, corresponding to a pH change of ~2 pH units. At 130 °C, the pH varied a little after switching from HS1 to LS1, and then it stabilized at about 8.3, corresponding to a pH gradient of ~ 1.3 pH units. Finally, the test at 40 °C was repeated. This time, a large increase in pH was noticed, about 2.7 pH units. In all cases, the pH returned to about 7, when LS1 was exchanged with HS1, due to the displacement of H+ by Ca2+ at the clay surface. For each of the four pH screening tests, effluent fractions were also analyzed for Ca2+ and SO42-, and the results are presented in Fig. 5. 1 Note that no sulfate was initially present neither in the HS1 nor in the LS1 brine, and Ca2+ was only present in the HS1 brine. In the first test at 40 °C, the concentration of SO42- and Ca2+ in the effluent was the same, 11 mM, during the flooding with the LS1 brine, which indicates dissolution of anhydrite, CaSO4 (s). At 90 °C, the concentration of SO42- in the effluent decreased to a value between 0.01-0.1 mM, while the concentration of Ca2+ stabilized slightly below 1 mM. At 130 °C, the concentration of SO42- was continuously low, between 0.01 and 0.1 mM, and the concentration of Ca2+ was below 1.0 mM. The conclusion from this observation was that dissolution of anhydrite decreased gradually, and the amount of Ca2+ during the LS1 flood was primarily linked to desorption of Ca2+ from the clay minerals according to Eq. 1. The final test at 40 °C showed ion concentrations of Ca2+ and SO42- close to the values observed in the test at 130 °C. Thus, easily available anhydrite had been dissolved after the first two tests at 40 and 90 °C. As pointed out previously, for core material containing clay minerals it has been suggested that the increase in pH as the flooding fluid is switched from HS to LS fluid is related to the exothermic reaction shown in Eq. 1. It has also been experimentally verified that the LS EOR 7 ACS Paragon Plus Environment

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effect decreases as the temperature increases.12-13 The increase in pH, when the HS brine is exchanged with the LS brine, decreases as the temperature increases.12-13 Therefore, there must be a correlation between the LS EOR effect and the pH gradient at given reservoir conditions. If the chemical equilibrium, Eq. 1, is moved to the left, the pH decreases due to a decrease in the OH- concentration. Desorption of Ca2+ from the clay surface can be decreased in two ways: (1) Supply heat, i.e. increased reservoir temperature. (2) Supply of Ca2+ ions, i.e. dissolution of anhydrite, CaSO4(s). To explain the lack of LS EOR effect from core RC3a, Fig. 1, there are two possibilities: (1) Combination of high Tres and very high concentration of Ca2+ in the FW1 will make the rock too water wet. (2) Dissolution of anhydrite can suppress desorption of Ca2+ from the clay surface. To investigate the lack of LS EOR effect we decided to remove dissolvable anhydrite from the core RC3b before a new oil recovery test. Oil recovery test, effect of anhydrite The anhydrite was removed by flooding the cleaned RC3b core with NaCl brine (1000 ppm) at ambient temperature until the concentration of SO42- in the effluent was well below 0.1mM. Core restoration was performed in the same way as for the RC3a core, and the flooding sequence was FW1 – SW- d50SW. Similar to the RC3a core, no LS EOR effect was observed for the RC3b core, Fig. 6. The ultimate oil recovery was, however, lower, about 57% of OOIP compared to 65% for the RC3a core. The initial pH of the formation water was below 6, and the pH increased by ~1.5 pH units, when switching from FW1 to SW, which was significantly higher than for the core containing anhydrite, Fig. 7. This is in line with a much smaller dissolution of anhydrite for the RC3b test. The concentration of SO42- in the produced FW1 was about 0.07 mM, compared to 2-4 mM for the Core RC3a, which was not depleted in anhydrite, Figs. 8 and 3 respectively. The concentration of SO42- in the effluent of d50SW decreased to ~0.1 mM for the RC3b core, which is even lower than the concentration of SO42in d50SW, 0.5 mM. Thus, since no LS EOR effect was observed for none of the cores RC3a and RC3b, the lack of LS EOR effect for core RC3a at the present conditions cannot only be caused by increased dissolution of anhydrite as the diluted SW was injected. The observed pH of the first eluted FW1 was below 6, which should indicate possible adsorption of organic material onto the clay minerals. A relevant question to be asked is: ”Will the combination of high temperature and high salinity formation water decrease adsorption of polar organic components onto the clay minerals?” If this is the case, then the potential of LS EOR effect will be reduced drastically. Therefore, the effect of salinity and pH on the adsorption of the basic organic model compound, Quinoline, onto Illite was studied at two different temperatures.

Static adsorption of Quinoline onto Illite It has previously been reported that the adsorption behavior of Quinoline (model basic material found in crude oil) onto Kaolinite showed a similar adsorption trend as crude oil, regarding both salinity and pH.4, 6,14 The present adsorption studies were performed at ambient 8 ACS Paragon Plus Environment

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temperature and at 130 °C using different brines termed: LS2 (~1000 ppm); HS2 (~25 000 ppm); CaCl2 (~25 000 ppm); FW3 (~200 000 ppm), Table 4. For each brine, three parallel tests were performed. Ambient temperature At ambient temperature, and in line with previous experiments,1, 4 the adsorption of Quinoline at pH 5 showed the expected trend between the LS2 and HS2 brine, i.e. the adsorption was higher in the LS2 compared to that in the HS2 brine, Fig. 9. The adsorption in the pure CaCl2 brine was quite similar to the HS2 brine. The brines had the same salinity, but the concentration of Ca2+ was quite different. Adsorption of Quinoline in the high saline brine FW3 showed, however, a completely different behavior. In this case the adsorption was slightly higher than for the LS2 brine. The adsorption trend in all brines can be explained by considering the behavior of Quinoline in contact with the different brines. In the LS2 brine there are less active cations to compete with the positively charged Quinoline for the negatively charged clay sites. In the HS2 and CaCl2 brine, cations can compete to a larger extent because of their higher concentration. Therefore, the adsorption of Quinoline dropped. In the extreme case with FW3 (~200000 ppm salinity), the Quinoline molecules are probably “salted out” of the water phase, and adsorption/precipitation is increased. After determining the adsorption of Quinoline at pH 5, the pH was increased to ~8 by adding a small amount of concentrated NaOH solution to the test tubes. For the LS2, HS2 and CaCl2 brines, the adsorption decreased drastically from 7-8 mg/g to about 4 mg/g. In the case of the high salinity FW3, only a very small decrease in adsorption was observed. The reversibility in the adsorption/desorption process was confirmed by decreasing the pH to ~5, and the adsorption in all brines increased to the same level as previously observed at pH 5. As a conclusion, the very high saline FW3 (200 000 ppm) brine behaved differently regarding adsorption/desorption of basic organic material onto Illite at room temperature compared to brines of lower salinities. High temperature, 130 °C The adsorption of Quinoline onto Illite at 130 °C and pH ~5 followed the same trend as observed at room temperature for the LS2, HS2, and CaCl2 brines, Fig. 10. For all brines, the adsorption was significantly lower than observed at room temperature, Fig .9. This can be explained by dehydration of the active cations at higher temperatures, which increased their reactivity towards the clay surface. In the same brines, a significant desorption was noticed when the pH was increased to ~8. However, the high salinity formation water, FW3, behaved differently. The initial adsorption of Quinoline onto Illite was less than 4 mg/g, i. e. the lowest adsorption at pH 5. No desorption was noticed when the pH was increased to ~8. In all the tested brines, re-adsorption of Quinoline took place as the pH was again decreased to ~5. For the high salinity formation brine, FW3, the re-adsorption was higher than the initial adsorption. The general trend observed is that the adsorption of basic organic material onto Illite clay decreases at very high temperatures for all the tested salinities. The lowest adsorption at pH 5 was observed for the very high salinity brine (~200 000 ppm), and no desorption was noticed 9 ACS Paragon Plus Environment

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when the pH was increased from 5 to 8. It has previously been confirmed that Quinoline behaved similar to crude oil regarding adsorption onto Kaolinite in terms of salinity and pH,14 and by assuming a similar behavior towards Illite, the present results clearly indicates that adsorption of organic material onto clay minerals is drastically decreased at high temperatures and high salinities of the formation waters. This is in line with the observed lack of LS brine EOR effects in the oil recovery tests. A follow-up question is: “Could we observe low salinity EOR effects at high temperatures if the formation water salinity is low?” It should be possible because a lower concentration of Ca2+ ions will favor active acidic and basic material in the crude oil in competition with Ca2+ regarding the adsorption process onto the negative sites of the clay. This hypothesis is tested by using the preserved core RC3c which has been depleted in anhydrite.

LS EOR effect at high Tres and low salinity FW The core RC3c was restored and tested in the same way as for the previous oil recovery tests, but now using FW2 with a salinity of 22 763 ppm. The oil recovery by injecting FW2 was 60 %OOIP, which was in between the recoveries from core RC3a and RC3b, Fig. 11. As expected, no increase in oil recovery was noticed when switching from FW2 to SW. The salinity of SW is about 33 000 ppm, and the concentration of Ca2+ is 13 mM, which is higher than in FW2. However, a significant increase in oil recovery of almost 6% of OOIP was observed when switching from SW to d50SW. The pH as well as the density of the produced water was logged during the flooding sequence, Fig. 12. The pH of the first water eluted from the core was 6.5, showing acidic condition due to the presence of CO2. As the volume of injected FW2 brine increased, the pH increased slightly above 7. A small decrease in pH to 7 was noticed when the FW2 was exchanged with SW, probably because of displacement of H+ from the clay surface by increased concentration of Ca2+ present in SW. According to Table 2, the concentration of Ca2+ in FW2 was only 27% of the Ca2+ concentration in SW. When the flooding fluid was switched to the low salinity brine, d50SW, the pH increased to 8.2, which is significantly higher compared to the values observed in the two previous oil recovery experiments. Due to a lower pH observed during SW injection on core RC3c (fig. 12) compared to the value observed on core RC3b (fig 7), it is possible to induce a pH gradient high enough to give a LS EOR effect. A larger increase in alkalinity promotes improved wettability alteration, and we observed a LS EOR effect. Thus, in the same way as a decrease in temperature can result in LS brine EOR effects even at very high salinities, a decrease in the salinity/Ca2+ concentration of the formation water can also promote LS brine EOR effects at high temperatures. The EOR effect appeared to be affected by a combination of initial wetting properties, and desorption of Ca2+ from the clay surface.13 LS EOR effects can be observed if there is a balanced adsorption of Ca2+, H+, and organic material onto the negatively charged clay surface. The relative adsorption of the different components is dictated by their concentration and reactivity. At high salinities (high concentration of Ca2+) and high temperature, adsorption of Ca2+ will dominate over organic material, and the rock becomes too water wet, even though the pH of the formation water is well below 7.


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General comments to the LS EOR effect The experimental observations are discussed in relation to our previously suggested chemical mechanism for the LS brine EOR-effect in sandstones. The key steps are desorption of Ca2+ from the clay surface followed by a local increase in pH close to the water-clay interface. Organic acidic and basic anchor molecules are then desorbed from the clay surface by an ordinary acid-base reaction transforming the adsorbed molecules into less reactive species2, 4. The experimental observations are in line with the suggested mechanism. Precipitated anhydrite, CaSO4(s), can be observed in reservoirs at high temperatures and high brine salinity. Increased dissolution of anhydrite as the low salinity brine invades the porous medium may decrease desorption of Ca2+ from the clay minerals. In that way, the increase in pH is suppressed with the consequence of reduced wettability modification. In the present work, two twin reservoir cores with and without anhydrite present, gave no LS EOR effects at high temperature, Tres=110 °C, when using a very high salinity formation water, about 200 000 ppm with very high concentration of Ca2+, 640 mM. Based on the results from the static adsorption studies, it is likely that the combination of high temperature, high salinity and high Ca2+ concentration of the FW decreases the adsorption of organic material onto the clay minerals. Even though the amount of clay minerals was high, ~16 wt%, the reservoir rock was probably too water wet for showing LS brine EOR effects at the present conditions.

Conclusions There are parameters/factors that may disturb the wettability alteration during a LS EOR process. The combination of certain minerals, temperature, salinity and composition of formation water could have a negative impact on possible LS EOR potential. Based on the results from the present work, the following main conclusions can be drawn: (1) Oil reservoirs at high temperature, Tres>100 °C, and high salinities, ~200 000 ppm, with high Ca2+ concentration may appear too water wet for observing LS brine EOR effects even though the clay content is high, ~16 Wt% and the crude oil contains significant amounts of polar components, BN > 1.0 mg KOH/g. (2) LS brine EOR effects can be observed at high temperatures, Tres>100 °C, provided that the salinity of the formation water is low, about 23 000 ppm. (3) Since desorption of active Ca2+ from the clay minerals is an exothermic process, increased temperature will also lower the LS EOR potential due to a small pH gradient. (4) Dissolution of anhydrite, CaSO4(s), will supress the desorption of Ca2+ from the clay surface and lower the LS EOR potential due to decreased pH gradient.

Acknowledgement Talisman Norway is acknowledged for the supply of reservoir core material.

References (1)

Aksulu, H., Håmsø, D., Strand, S., Puntervold, T. and Austad, T., 2012, Energy Fuels 26, 3497-3503. 11 ACS Paragon Plus Environment

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(2)

Austad, T., RezaeiDoust, A. and Puntervold, T. (2010). "Chemical mechanism of low salinity water flooding in sandstone reservoirs." Paper SPE 129767 prepared for presentation at the 2010 SPE Improved Oil Recovery Symposium, Tulsa, Oklahoma, USA, 24-28 April.

(3)

Reinholdtsen, A. J., RezaeiDoust, A., Strand, S. and Austad, T. (2011). "Why such a small low salinity EOR - potential from the Snorre formation?" 16th European Symposium on Improved Oil Recovery, Cambridge, UK, 12-14 April.

(4)

RezaeiDoust, A., Puntervold, T. and Austad, T., 2011, Energy Fuels 25, 2151-2162.

(5)

Madsen, L. and Lind, I., 1998, SPE Res. Eval. Eng. February, 47-51.

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Fogden, A., 2012, Coll. Surf. A 402, 13-23.

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Morrow, N. R., 1990, J. Pet. Tech. December, 1476-1484.

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Burgos, W. D., Pisutpaisal, N., Mazzarese, M. C. and Chorover, J., 2002, Environ. Eng. Sci. 19 (2), 59-68.

(9)

Xie, Q., Liu, Q., Ma, D. and Wu, J. (2012). "Influence of brine composition on C/B/R interactions and oil recovery in low permeability reservoir cores." The 33rd annual IEAEOR conference and symposium, Regina, Canada, 27-30 August.

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Strand, S., Austad, T., Puntervold, T., Aksulu, H., Haaland, B. and RezaeiDoust, A., 2014, Energy Fuels 28, 2378-2383.

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Springer, N., Korsbech, U. and Aage, H. K. (2003). "Resistivity index measurement without the porous plate: A desaturation technique based on evaporation produces uniform water saturation profiles and more reliable results for tight North Sea chalk." Paper presented at the International Symposium of the Society of Core Analysts Pau, France, 21-24 Sept.

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Gamage, P. and Thyne, G. (2011). "Systematic investigation of the effect of temperature during aging and low salinity flooding of Berea sandstone and Minn." 16th European Symposium on Improved Oil Recovery, Cambridge, UK, 12-14 April.

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RezaeiDoust, A., Puntervold, T. and Austad, T. (2010). "A discussion of the low salinity EOR potential for a North Sea sandstone field." Paper SPE134459 presented at the SPE Annual Technical Conference and Exhibition, Florence, Italy, 19-22 September.

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Fogden, A. and Lebedeva, E. V. (2011). "Changes in wettability state due to waterflooding." The International Symposium of the Society of Core Analysts, Austin, TX, USA, 18-21 September.


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Table 1 Reservoir core data. Core # RC1 RC3a RC3b RC3c

Illite/Mica Wt% 11.2 6.7 6.7 6.7

Kaolinite Wt% 8.7 8.3 8.3 8.3

Chlorite Wt% 0.8 1.2 1.2 1.2

Total Clay Wt% 20.7 16.2 16.2 16.2

Porosity Φ, % 15.7 15.3 15.3 15.4

Permeability k, mD

3.9

Table 2 Ion composition, Ionic Strength (IS) and Total Dissolved Solids (TDS) of brines used in the oil recovery tests (mM = 10-3 mole/l). Ions Na+ K+ Ca2+ Mg2+ Ba2+ Sr2+ HCO3ClSO42IS TDS, mg/l

FW1 mM 1915.0 33.0 640.0 80.0 7.0 8.0 3417.0 4.152 195 680

FW2 mM 370.9 3.1 3.5 1.4 0.6 0.9 2.7 384.0 0.393 22 763

SW mM 450.1 10.1 13.0 44.5 2.0 525.1 24.0 0.656 33 390

d50SW mM 9.0 0.2 0.3 0.9 0.0 10.5 0.5 0.013 668

Table 3 Composition of brines used in the surface reactivity test. Ions Na+ Ca2+ ClIS TDS, mg/l

HS1 mM 1540.0 90.0 1720.0 1.810 100 000

LS1 mM 17.1 0.0 17.1 0.017 1000

Table 4 Brines used in the adsorption studies of Quinoline onto Illite. Ions Na+ Ca2+ Mg2+ ClIS TDS, mg/l

HS2 mM 295.9 37.5 37.1 445.1 0.520 24 990

LS2 mM 11.7 1.5 1.5 17.6 0.021 990

CaCl2 mM 0.0 225.3 0.0 450.6 0.676 25 000

FW3 mM 2085.8 536.1 143.9 3526.0 4.221 201 560

Table 5 Physical and chemical properties of stabilized crude oil

Crude Oil

AN [mg KOH/g]

BN [mg KOH/g]

Density (20 °C) [g/cm3]

0.25

1.17

0.852


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Fig. 1. Oil recovery test from core RC3a. The core was flooded successively with FW1→SW→d50SW with a rate of 4 PV/D at 110 °C.

Fig. 2. Density and pH of produced water samples during the oil recovery test of core RC3a.


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Fig. 3. Ca2+ and SO42- concentration of produced water samples during the oil recovery test of core RC3a (No SO42- was initially present in the FW1).

Fig. 4. Surface reactivity test of the 100% water saturated core RC1 at 40, 90 and 130 °C. pH of effluent samples was measured on during the brine flooding sequence , HS1→LS1→HS1. The switches of injection fluids are indicated by the dashed lines.1


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(a)

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(b)

(c) (d) Fig. 5. Ca2+ and SO42- concentration of effluent samples versus injected PV during surface reactivity test of core RC1. The flooding sequence was HS1→LS1→HS1, and the test was performed at a) 40; b) 90; c) 130; d) 40 °C.1

Fig. 6. Oil recovery test from core RC3b. The core was flooded successively with FW1→SW→d50SW with a rate of 4 PV/D at 110 °C. RC3b was initially depleted in Anhydrite.


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Fig. 7. Density and pH of produced water samples during the oil recovery test of core RC3b. RC3b was initially depleted in Anhydrite.

Fig. 8. Ca2+ and SO42- concentration of produced water samples during the oil recovery test of core RC3b which was initially depleted in Anhydrite. No SO42- was initially present in the FW1.


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Fig. 9. The effect of pH on the adsorption/desorption of Quinoline onto Illite clay at ambient temperature in brines with different salinities/ion composition.

Fig. 10. The effect of pH on the adsorption/desorption of Quinoline onto Illite clay at 130 °C in brines with different salinities/ion composition.


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Fig. 11. Oil recovery test from core RC3c The core was initially depleted in Anhydrite. The core was successively flooded with FW2→SW→d50SW at a rate of 4 PV/D at 110 °C.

Fig. 12. Density and pH of produced water samples during the oil recovery test of core RC3c. The core was initially depleted in Anhydrite


Composition on the Low-Salinity

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