Effect of ionic composition in water: oil interactions in adjusted brine chemistry waterflooding: preliminary results

Low salinity or adjusted brine composition waterflooding (LSW or ABCW) is considered a promising improved/enhanced oil recovery (IOR/EOR) method. Despite the large number of studies documented in the literature, there are contradictory results and a lack of consensus regarding the mechanisms that operate in this recovery process. The proposed fluid:rock and fluid:fluid mechanisms are still under discussion and investigation. However, the impact of oil geochemistry and its importance on the fluid:fluid interactions that can occur with brines during LSW or ABCW have been overlooked and studied in a lesser extent. The scope of the present study is to preliminary evaluate crude oil:brine interactions to validate the influence of its compositions. These interactions were evaluated at static conditions for a week and reservoir temperature (60°C) using two oil samples from different Colombian basins and brine solutions of different composition at a constant ionic strength (I = 0.086). Specifically, this investigation evaluated the effect of the type of cation (Na + and Ca 2+ ) and anion (Cl - and SO 4 = ) on crude oil:brine interactions. The results of these experiments were compared with tests using distilled water (DW). Although a basic characterization of brines (i.e. pH, alkalinity and ionic composition) and oil (oil viscosity) was performed, the main objective of this study is the analysis of water-soluble organic compounds (WSOC) using Fourier Transform Ion Cyclotron Resonance Mass Spectrometry (FT-ICR MS). The results demonstrate that water:oil interactions are dependent on brine and crude oil compositions. The main changes observed in the aqueous phase were the increase in inorganic components (desalting effects) and organic compounds soluble in water. Only the system crude oil A and NaCl (5,000 ppm) showed the formation of a micro dispersion. Negative electrospray ionization (ESI (-)) FT-ICR MS data shows that WSOC’s identified in DW and Na 2 SO 4 after the interaction with crude oil A belongs to similar classes but there is marked selectivity of species solubilized with different brines. The relative abundance of classes O x , O x S and NO x (x > 2) decreases while O x , O x S and NO x (x ≤ 2) increase their solubility in the presence of Na 2 SO 4 compared to DW. The analysis of O2 and O3S classes using double bond equivalence (DBE) vs. carbon number (CN) contour plots shows that the isoabundance of water-soluble species are within the range of DBE £ 10 and CN £ 20 regardless the brine used in the experiments. Finally, the method of solvent extraction in silica columns used in this investigation for the analysis of WSOC using FT-ICR MS represents a powerful and new approach to study LSW and ABCW. Petroleómica, Transformada De Fourier-Resonancia de Ciclotrón Iónica- Espectrometría de Masas (FT-ICR MS), Electro Pulverización Iónica (ESI).


Introduction
The injection of Low Salinity Water (LSW) is considered a promising method for improving oil recovery. This injection technique is gaining attention based on the multiple research documented in the literature. LSW is also referred in the literature as Advanced Ion Management, Designer Water Flood, Engineered Water Flooding, LoSal™ and Smart Water Flood, among others (Al-Shalabi & Sepehrnoori, 2016) (Kilybay, Ghosh & Thomas, 2017). For simplicity and integrate different concepts and approaches, in this paper authors will use the term Adjusted Brine Chemistry Waterflooding or ABCW (Alvarado, Garcia-Olvera & Manrique, 2015).
The increase of oil recoveries using low (fresh) salinity waters was first reported at lab scale by Bernard (1967). Incremental oil recoveries were attributed to fluid:rock interactions, specifically due to clay migration and/or swelling. As of today, there is no consensus regarding the mechanisms operating during ABCW. In fact, there are conflicting results between different studies that explains the difficulties to interpret existing experimental results (Skauge, 2013) ( It is important to mention that most of ABCW research have been mainly focused on the fluid:rock interaction. However, the impact of the oil geochemistry/ composition on fluid:fluid interactions during ABCW have been overlooked and studied in a lesser extent. This is somehow surprising based on the evidences of organic compound transfer from the oil to the water phase in different processes well documented in the literature. Some examples include but are not limited to: • Willey, Kharaka, Presser, Rapp & Barnes (1975) and Palandri & Reed (2001) reported the importance of the presence of organic acid anions (OAA) in the total alkalinity of oilfield waters. They also report that the OAA are potential sources of CO 2 (thermal decarboxylation) and buffering agents in reservoir waters.  Larter & Aplin (1999) reported the importance of water washing effects in organic geochemistry and its potential applications for exploration, reservoir characterization and monitoring. Water washing is the stripping of water-soluble organic compounds from the oil into the aqueous phase. Additionally, Lafargue & Barker (1988) concluded that water washing was more effective in fresher waters and higher temperatures. • Khatib & Salanitro (1997) proposed the mechanisms of reservoir souring and suggested that the main variables responsible of these souring effects appears to be the sulfate concentration, organic acid content (i.e. low molecular weight carboxylic and fatty acids) and the salinity of produced waters. • Kaasa & Østvold (1997) and Wang et al. (2014) also demonstrated the influence of the presence of organic acids naturally present in formation waters on water total alkalinity. In simple terms the alkalinity of produced waters can be expressed with the following equation: Alkalinity ≈ [HCO 3 -] + Σ [organic acid anions].
However, most recently the effect of fluid:fluid (crude oil:brine) interactions on the recovery mechanisms of ABCW have been recognized. Some studies addressing the importance of water-soluble organic anions in ABCW are summarized below: • Wang & Alvarado (2011) report that in general low ionic strength brines favors the formation of stable water-in-oil emulsions. They also found that as the oil-to-water ratio increase emulsion stability also increase suggesting that the interfacial-active fractions from the oil plays an important role on emulsion stability. demonstrated that the brine solution can alter the micro forces at the oil-water interface. This research found that the brine concentration has a significant effect on the amount of emulsion formed and that its formation significantly depends on the crude oil composition. • García-Olvera, Reilly, Lehmann & Alvarado (2016) reported that the emulsion stability is a complex function of the dynamic interfacial properties and does not correlate to oil recovery. They also observed that the organic acids present in oil play an important role in the values of the viscous and elastic components of the interface rheological characteristics. Additionally, and as expected, the organic acid distribution was found to be oil specific based on 1H NMR (Proton Nuclear Magnetic Resonance) data summarized in this study. • Ayirala, Li, Saleh, Xu & Yousef (2018) studied the effects of salinity and water ions on crude oil-Water Interface identifying that higher interfacial tensions (IFT) were obtained with deionized (DI) water vs. brines at elevated temperature. They also found that the IFT in the same brine were generally higher at ambient temperature compared to elevated temperature. Finally, DI and sulfate-rich brine showed a delayed coalescence of crude oil droplets with respect high salinity multivalent brine containing calcium and magnesium. Collins et al., (2018) reported the changes of crude oil composition during low salinity waterflooding (LSW) using High Resolution Mass Spectrometry (HRMS). The results of this research confirmed the changes in composition of the produced oil during the low salinity brine injection. This study also reports that the release of fatty acids is consistent with LSW mechanisms involving wettability changes due to binding of polar molecules, especially carboxylic acids, at the rock surface.
The main objective of this work is to preliminary evaluate crude oil:brine interactions to validate the influence of its compositions. This study will summarize preliminary results of a larger research program evaluating ABCW. The study was developed by means of static experiments using two oil samples from different Colombian basins and brine solutions of different composition at a constant ionic strength. Specifically, this investigation evaluated the effect of the type of cation (Na + and Ca 2+ ) and anion (Cland SO 4 = ) on crude oil: brine interactions. The results of these experiments were compared with tests using distilled water (DW). The evaluation of the crude oil:brine interactions was performed by measuring possible changes in the water (i.e. pH, alkalinity, ionic composition and water-soluble organic compounds) and the oil (i.e. viscosity) phase. Finally, the analysis of water-soluble organic compounds transferred from the crude oil were analyzed using Fourier Transform Ion Cyclotron Resonance Mass Spectrometry (FT-ICR MS). Table 1 summarizes the main properties of crude oils used in this investigation. Oil sampling procedures were performed in separator tests after few days flowing without any chemical treatment. The oil:water interfacial tension (IFT) of both oil samples were measured to discard possible contaminants with chemicals. The IFT measured for crude oils A and B in DW water was 30.2 dynes/cm and 31.2 dynes/cm, respectively. These values are considered reasonable and within the acceptable ranges for laboratory experiments. No further treatment were performed to the oil samples avoiding any possible alteration compared to current oil properties at reservoir conditions, except for the gas in solution liberated during the sampling. Crude (dead) oil:brine interactions were studied at reservoir temperature (60°C) in batch experiments for a period of one week. The oil:brine systems were stirred periodically to promote the contact between both phases. However, most of the interactions occurred at static conditions. DW and brine solutions of NaCl, CaCl 2 and Na 2 SO 4 were used in these experiments. Brine solutions were prepared using reagent grade chemicals and DW. The effect of the type of cation (Na + and Ca 2+ ) and anion (Cland SO 4 = ) on crude oil: brine interactions were tested at a constant ionic strength (I = 0.086) that is equivalent to a NaCl concentration of 5,000 ppm. The oil-to-water ratio used in these experiments was 50:50 using a total volume of fluid of 80 cc.

Experimental Study
After one week of interaction, fluids were separated to perform the characterization of both phases. The pH, alkalinity (ASTM D 1067-92) and ionic composition of DW and brine solutions were measured before and after the interaction. Calcium was measured by titration method (ASTM D 511-92) and Chloride and Sulfate were measured using the Mohr (SM 4500-Cl D) and turbidity (ASTM D4130-82) methods, respectively. The type and distribution of water-soluble organic compounds (WSOC) transferred from the oil to the water phase were analyzed using Fourier Transform Ion Cyclotron Resonance Mass Spectrometry (FT-ICR MS). WSOC were first extracted from water following established protocols well described in the literature (

Results and Discussions
After seven day of interaction no major evidences of dispersions in the water phase or in the oil:water interface were observed in all experiments. Figure 1 shows a picture of the crude oil A and brine systems tested after 1 and 7 days interacting at reservoir temperature (60°C). Despite the apparent low reactivity of crude oils (A and B) evaluated, the pH of the water phase after interacting with both oils suggest that these interactions are oil dependent (Figure 2).
Both oils showed the largest pH changes when interacting with distilled water. However, trends in pH resulted completely opposite. Crude oil A increased and crude oil B decreased the pH with respect the initial pH of the DW (Figure 2). This result suggest that the crude oil composition plays an important role in low salinity waters as reported by Lafargue and Barker (1988). Based on the pH changes measured, crude oil A seems to show higher reactivity with DW and CaCl 2 compared to NaCl and Na 2 SO 4 . For the brines evaluated, final pH are similar or higher when interacting with oil A for 7 days at 60°C. On the contrary, oil B shows a similar pH reduction behavior regardless the brine used in the experiments. These differences in pH trends observed with oils A and B can also suggests that the nature of the organic compounds transferred from the oil to the water phase should be different and dependent on the crude oil geochemistry or molecular composition. Regarding the alkalinity of the brines after interacting with both crude oils, the changes were minor except in the system oil A and CaCl 2 . This system reported an increase in alkalinity with respect the initial CaCl 2 solution. Overall, oil A did not change the alkalinity of DW, NaCl and Na 2 SO 4 solutions after interacting for a week. On the other hand, all brine solutions tested decreased its alkalinity after the reaction with oil B. However, these changes were within the experimental error and are not considered conclusive. Nevertheless, due to the minor changes measured in the alkalinity of the brines the analytical method (ASTM D 1067-92) used seems to be inadequate for the experimental conditions used in this study.  Changes in the chloride concentrations were also observed with both oils showing different behavior ( Figure 4). All brines evaluated (DW, NaCl, CaCl 2 and Na 2 SO 4 ) showed an increase in chloride concentration after the interaction with oil A. However, oil B did not generated changes in chloride concentration. The reduction in chloride concentrations reported after the interaction of oil B with NaCl and Na 2 SO 4 are within the experimental error and will not be discussed in this paper. The importance of these simple static experiments demonstrates that crude oil:brine interactions are specific for each oil and reservoir system. For example, the transfer of calcium from the oil to the water phase ( Figure 3) can be explained due to the presence of oil in contact with carbonate cement in sandstone reservoirs and hardness of formation and/or injection brines (i.e. oil A). In this particular case calcium can be present either as an inorganic salt (i.e. calcium chloride) or in the form of organometallic compounds (i.e. calcium naphthenates).
Furthermore, the increase in chloride concentration in the aqueous phase after the interaction of oil A:brine systems (Figure 4) strongly suggest that in presence of lower salinity brines oil A suffer a desalting process. The desalting process is a well-known operation performed to remove salt and water from crude oils before sending a stream of oil to the refining process because of their negative effects in downstream processes such as  3 & 4). If the effects of desalting of crude oils with low salinity brines (ABCW) are present during coreflood experiments, it may lead to misinterpretation of oil recovery mechanisms (i.e. double layer and ionic exchange). Therefore, desalting effects of crude oils must be validated before evaluating possible oil recovery mechanisms of ABCW at laboratory scale.
Regarding the oil phase viscosity, minor changes were observed but within the experimental error except for the oil A after interacting with NaCl ( Figure 5). All viscosities were measured at a shear rate of 7.33 s -1 and reservoir temperature (60°C). Oil A increased 2.6 cp after interacting with the NaCl solution. Analyzing a sample of the oil:water interface of this system (Oil A:NaCl) using an optical microscope confirmed the presence of a micro-dispersion ( Figure   6). The presence of this micro-dispersion (water-in-oil emulsion) can explain the increase of the oil viscosity measured after the experiment. This result agrees with the study reported by Mahzari & Sohrabi (2015) that demonstrated the formation of micro-dispersions in LSW and its importance on incremental oil recoveries observed at laboratory scale. Wang & Alvarado (2011) also reported that low ionic strength favored the formation of stable water-in-oil emulsions using oil samples from Wyoming reservoirs at different salinities and water:oil ratios at 25°C. Additionally, their study also found that calcium played a key role in emulsion stability compared to sodium. However, these results differ from those observed in this study where sodium (NaCl) was the only brine that formed a stable micro-dispersion with oil A. The later represents another evidence that mechanisms of LSW or ABCW are oil/reservoir specific. Therefore, propose general screening criteria for this recovery process represents a difficult task. The molecular level composition of the WSOC transferred from Oil A was analyzed throughout ESI(-) FTICR MS and compared with the classes detected for crude Oil A.  (Figure 7).  (Turner, 2003). For instance, polar functional groups, alkyl branching, and aromatization decrease hydrophobic surface area, whereas alkyl chains increase hydrophobic surface area. This effect is more noticeable for the Na 2 SO 4 brine, where electrostriction decreases the area into which hydrophobic moieties may solvate between more ordered water molecules. As a result, relatively shorter, less aromatic and less oxygenated polar molecules are present in water when Na 2 SO 4 is present. In its place, relatively larger, more aromatic and more oxygenated compounds are dissolved in distilled water (see figure 7 to compare). These results agree with previous reports where sea water-soluble organic species were studied (Stanford et al., 2007).

Conclusions
The water:oil interactions indicate that the composition of brines changes during the Adjusted Brine Chemistry Waterflooding (ABCW). The main changes observed were the increase in inorganic components (desalting effects) and organic compounds soluble in water.
This study strongly suggests that water:oil interactions are dependent on brine and crude oil compositions.
Preliminary results also suggest that oil properties such as TAN and SARA can't be used to predict the potential transfer of organic compounds from the oil to the water phase during ABCW. Therefore, greater efforts to understand oil geochemistry will contribute explaining the possible mechanisms that operate during the ABCW.
Of the systems evaluated (two oil samples and four different brines) only the crude oil A and NaCl (5,000 ppm) formed a micro dispersion. These results represent additional evidence of the influence of oil and brine compositions on water:oil interactions during ABCW.