The Impact of Naphthenic Acids on Dynamic Fluid–Fluid Interactions: Implication for Enhanced Oil Recovery

Abstract

Previous coreflooding results and wettability analyses in our group show that injection of naphthenic-acid-enriched water can improve oil recovery over traditional waterflooding. This observation is still a subject of research efforts without a definitive explanation. Naphthenic acids (NA) have been reported to drive wettability alteration and increase the water–oil interface elasticity. These alterations depend on the NA carbon number and aqueous-phase salinity, among other conditions, as reported in the literature. Smart-water flooding (SWF) research often links recovery to the initial wettability condition, being higher for initially oil-wet rock. SWF refers to a technique in which the aqueous-phase ion composition or/and salinity are changed to maximize oil recovery. Given NAs’ complex solution behavior, selecting acid combinations that prompt oil recovery is a difficult objective. The aim of this research is to determine the effects of select naphthenic acids on the oil–water interfacial rheology and wettability alteration and how these interfacial effects are associated with oil recovery under spontaneous imbibition. NAs were selected based on their carbon number, molecular structure, and solubility in the saline solution used in this research. We aimed at exploring which NAs should be used to regulate interfacial properties so as to either increase oil recovery or accelerate production. Time-domain nuclear magnetic resonance, interfacial dilatational rheology, and liquid-bridge experiments, i.e., proxy of snap-off, were conducted. A baseline was established using results obtained with a previously tested sulfate-rich aqueous phase, shown to be effective in recovering oil. Results show that NA14 and N18 increase the water–oil interfacial viscoelasticity and induce interfacial healing but led to different recovery factors. N10, while effective at inducing water wetness in oil-wet rock, is ineffective at increasing the recovery factor. We concluded that wettability and oil–water interfacial rheology are not exclusive, and instead they can synergistically favor EOR benefits. Moreover, oil recovery benefits under spontaneous imbibition are shown to depend strongly on the initial wettability conditions.

1. Introduction

The benefits of low-salinity (<5000 mg/L salinity) or smartwater waterflooding in sandstone reservoirs have been attributed to effects of water/salinity/modified chemistry on rock wettability [1,2,3]. Smartwater flooding (SWF) is a technique in which the aqueous-phase ion profile or composition and/or the salinity of the injected water is adjusted to maximize the oil yield or recovery [4]. In this sense, low-salinity waterflooding (LSWF) is a subset of SWF, in which the modification consists of a significant reduction in the ionic strength of the injected water. Among the mechanisms proposed to explain the improved oil recovery under SWF [4], the alteration from oil-wettability to a water-wetting condition has been linked to the observed oil recovery improvement in contrast with results obtained using higher salinity. Regardless of what causes it, water wetting is thought to aid oil and water fluid distribution with an increase in oil mobility. This association is unlikely the only mechanistic explanation for enhanced recovery. In fact, there are reported cases in which oil recovery improved without an apparent wettability alteration. Zahid et al. [5] noticed improved oil recovery in the presence of a significant concentration of sulfate in solution without an apparent wettability modification, as per contact-angle measurements. In this case, experiments were conducted without a significant aging period to minimize the wettability alteration. Zahid et al. [6] also reported a sulfate-induced oil viscosity alteration at high temperatures, which was proposed as the reason for enhanced recovery. In Zahid’s research [5,6], oil composition was found to be relevant. Since then, fluid–fluid interactions have been under closer scrutiny.

Additional research has shown that fluid–fluid interactions can arise in SWF [7,8]. Moradi et al. [7] reported high oil recovery in coreflooding experiments for a crude oil having a high total acid number. When compared with crude oils from the same basin with a lower acid number and a higher asphaltene content, the recovery factor was significantly higher. This brought up the question as to what the role of these acids was. On the other hand, Garcia-Olvera and Alvarado [8] showed that even at high ionic strength, the addition of sulfate (6.7 millimoles (mM) ionic strength (IS) or 1% Na₂SO₄) increases the fluid–fluid interface elasticity. One argument supporting the need for a fluid–fluid interfacial regulation is the enhancement in oil-neck snap-off events by collapse of water collars in pore-throats of water-wet porous systems [7]. Garcia-Olvera and Alvarado’s work [8] concluded that increased visco-elasticity decreases oil choke-off (snap-off) and increases ganglia coalescence, ultimately improving oil recovery. To understand this, it must be pointed out that an increase in coalescence will favor oil connectivity, which renders the oil phase more mobile. However, evidence in the literature suggests that in addition to the ion species in the brine, the oil characteristics also play an important role.

Crude oil is typically characterized by its four solubility classes: saturates, aromatics, resins, and asphaltenes. The most polar of these are the asphaltenes, which have been found to be more interfacially active. Their influence can be seen in refining operations such as the prompted emulsion formation and asphaltene precipitation, among others [9,10,11,12,13]. Additionally, naphthenic acids (NAs) also play an important role. These acids are naturally available as the byproducts of in-reservoir biodegradation of hydrocarbons, which serve as biological markers of maturity and degree of biodegradation in the reservoir [14,15,16]. Viscoelasticity has been shown to relate to both the asphaltene content and the presence of organic acids, contributing to interface buildup over time. Oils with more asphaltene exhibit progressively higher viscous and elastic interfacial moduli [9,10]. The role of these small organic acids in SWF is still a subject of debate. NAs have been shown via molecular modeling and microbalance experiments to affect desorption efficiency in sandstone [17]. Deng et al. showed the importance of organic acid molecular length and structure on oil-wetting on both sandstone and carbonate surfaces [18]. The issue is the existence of confounding variables, e.g., the uncontrolled aqueous phase ionic strength, but also the fact that naturally occurring organic acids are a complex mixture ranging from low- to high-solubility species in water, with potentially opposing effects. This question requires a simpler experimental matrix to isolate the effects of individual acids and thereby reduce confounders.

Previous research shows that naphthenic acids will displace or interact with other components in proximity to the interfacial region to make them less available to the interface. For instance, sodium naphthenates compete with asphaltenes for adsorption, and as a result, they can hinder the development of an asphaltene-rich rigid interface [19]. Acidic and basic species are both present in the oil, and the change in aqueous pH elicited by contact with oil can be used to predict the likelihood of naphthenate scales [20]. Pulsed field-gradient spin echo (PFG-SE) nuclear magnetic resonance (NMR) results have shown that aggregates between acids and asphaltenes can form, but as a large variety of each exists, the aggregation state is highly dependent on which species are present and able to interact [12,21]. Density functional theory and molecular dynamics have been used to show the effect of salinity on solubility and the aggregation in aqueous solution of NAs [21]. The change in concentration of acidic species present in oil over time is also important. Herman et al. [22] have shown that small cycloalkanes are more susceptible to microbial degradation than their methylated counterparts in richer nutrient environments. Degradation pathways for n-alkyl cyclohexenes depend on several structural characteristics, such as the number of carbons that branch off the cycloalkane and the number of rings present [23,24,25,26,27]. In most oils, these acid species will be diverse and in a state of time- and exposure-dependent flux. Hoeiland et al. [28] have shown that the type of acid present can influence wettability alteration and interfacial tension more than the concentration of species present. They showed that acid structures with a greater influence were cyclohexane/pentanes and phenolic or alkyl acids compared to acids with high-molecular ring structuring. Fjelde et al. [29] researched the acid/base ratio of the oil and concluded that the composition of both brine and oil affect the adsorption of polar species on the rock, and therefore wettability. Brandal et al. [30] also noted that the structure of acids, among other parameters, combines to influence the interfacial tension. They noted a significant difference in interfacial penetration in aromatic species, as these species insert themselves more acutely and more densely than saturated components, even with multiple aromatic rings present. Smith et al. [31] showed that the presence of specific naphthenic acids in small concentrations affects fluid mobility and influences the ultimate recovery. The effects were in some cases beneficial, depending on whether the rock was initially either oil-wet or water-wet. The authors suggested that the ultimate recovery is a combination of wettability alteration and fluid–fluid interfacial properties. However, additional work was required to ascertain this statement.

Previous research has shown that for a specific crude oil, the recovery factor (RF) increases in corefloods when using a 1% Na₂SO₄ aqueous phase [8,9]. Additionally, naphthenic acids can be used to alter interfacial viscoelasticity and interfacial tension and thereby potentially improve oil recovery [9,31]. Gao et al. [19] showed the presence of a blend of naphthenic acids leads to interfacial softening and a self-evident increment in emulsion coalescence. Brocart and Hurtevent [32] determined that the type of acid is more important than its concentration in emulsion creation and stability.

The purpose of the research herein is to determine the effect of the addition of the three selected NAs on wettability and interfacial viscoelasticity and link those to trapping via snap-off and ultimate recovery. This research focuses on small acid species, either having a hexane ring or a pentane structure [28]. Interfacial viscoelasticity effects on interfacial mechanical stability are studied through emulsion stability through NMR and snap-off delay using a bridge pendant drop technique [33]. Results in bridge pendant drop experiments correlate well with microfluidic observations under water-wet conditions [7]. The analysis here focuses on highly water-soluble species, as they contributed to improved recovery in prior work [9]. A collection of NAs was screened according to solubility, thereby discarding those with poor solubility. Oil recovery results during spontaneous imbibition experiments in previous work are recalled in this work [31]. The selected benchmark consisted of the best-performing low-salinity aqueous phase solely utilizing sodium sulfate at low ionic strength. The hypothesis in this work is that if the addition of an NA yields interfacial results as good as or better than those elicited by a sodium sulfate solution, then performance enhancement should be comparable to that induced by the sodium sulfate aqueous solution.

2. Materials and Methods

Initially, 17 carboxylic acids were screened in this work: Dicyclohexyl acetic acid, cyclohexane pentanoic acid, 4-pentylbenzoic acid, 1-methyl-1-cyclohexane carboxylic acid, 5β cholanic acid, 2-hexyldecanoic acid, 4-phenylbutyric acid, cyclohexane acetic acid, 3-cyclohexane acetic acid, 3-cyclohexane propionic acid, 4-heptyl benzoic acid, p-toluic acid, decanoic acid, cyclopentane carboxylic acid, (±)-4-methyl octanoic acid, cyclohexane butyric acid, biphenyl-4-carboxylic acid, and cyclohexane carboxylic acid.

Additionally, L-proline and a naphthenic acid mixture containing various unspecified C12-C14 cyclic acids were obtained to contrast the results collected with a mixture proven to better oil recovery [9]. A sodium sulfate (Na₂SO₄) brine was selected as the base fluid. All chemicals were purchased from Sigma Aldrich (St Louis, MO, USA).

The oil analyzed herein was obtained from a sandy reservoir in Wyoming. The crude oil for these experiments is identified as GB and corresponds to the same oil used in Smith et al. [31] and Garcia-Olvera et al. [9]. All oil samples were centrifuged for four hours and filtered with a 90 mm Whatman ashless filter under nitrogen gas pressure before use. The oil was stored in amber jars to protect it from UV decomposition and shaken thoroughly before each use. The oil was analyzed for acid and asphaltene content, density, and shear viscosity.

2.1. Aqueous Solution Preparation

The base aqueous phase was prepared with sodium sulfate at 2.24 mM or 1% (low salinity), at a 6.7 mM ionic strength, and degassed a total of two hours before use. Saline solution aliquots were mixed with each acid solution at various concentrations. Several acids displayed low solubility regardless of various mixing times, heating, or the concentration used. No changes to the brine were attempted to solubilize the acids. At higher brine pH, larger NAs solubilize more promptly, while lower molecular weight acids often dissolve at neutral pH [34,35]. NA solubility in water was assessed via ¹H NMR in a similar fashion as in an earlier publication [36]. After examination, six were deemed essentially insoluble, while the others that showed any detectable level of solubility by means of NMR were compared for structural resemblance and spectral signal quality. The NMR procedure to collect spectra can be found in the methods section of this paper.

After examination, three NAs exhibited the highest solubility, as determined by spectroscopic NMR analysis, and structural diversity: 3-cyclohexane propionic acid (NA10), NA14, and NA18. The molecular structures comprise a cyclopentane, a cyclohexane, and a cyclohexane with a chain. In addition to allowing a comparison among similar structures, both NA14 and NA18 are reportedly present in crude oil [35]. All acids were tested at 1 mM and dissolved in aqueous solution. Figure 1 shows ¹H NMR spectra for the acids analyzed. Only NA18 was soluble at higher concentrations, but its concentration was kept at 1 mM for a better comparison with the other two acids. However, additional measurements were conducted at concentrations of 2.5 mM, 5 mM, and 10 mM for this acid to gain insights regarding the influence of higher concentrations [37].

A DMA 4500 Anton Paar density meter (Houston, TX, USA) and a VWR SympHony SB70P pH meter (Aurora, CO, USA) were used to measure density and pH of each aqueous phase, respectively. The pH was initially measured for each of the solutions to confirm the presence of acids through acidification of the brine. Thereafter, partitioning experiments were conducted at a 1:1 ratio of oil and water to detect changes in pH, showing that all systems experience a pH increase after being in contact with the oil. This observation likely indicates the release of some basic species from the oil. That is not the case for the base fluid (1% Na₂SO₄) that experiences a pH reduction (

Table 1. Changes in pH values (i represents initial and f represents final).

Acid	Mol. Weight	pHi	pHf
1 mM NA10	156.22	4.48	5.48
1 mM NA14	114.14	4.35	4.82
1 mM NA18	128.17	4.88	5.06
1% Na2SO4	–	7.13	7.00

). It is important to mention that pH values will not be used further other than to show the presence of acids.

2.2. Crude Oil Preparation and Characterization

The Anton Paar DMA 4500 density meter (Houston, TX, USA) was used to measure the oil density. The asphaltene content was estimated after mixing an oil aliquot at a 40:1 by weight solution of analytical grade n-pentane to oil for 24 h to drop out C5-asphaltenes. The mixture was then filtered through a 0.45 µm PFGSE filter paper using a vacuum pump. Then, pentane was used to rinse until the solution was clear to avoid asphaltene precipitation on the glass. The mixture was dried under vacuum until small fissures were visible on the dry asphaltene layer on the filter. The asphaltenes precipitated and filtered were allowed to dry in an oven until no changes in the mass were observed and only the precipitate remained. The fraction of asphaltene was estimated gravimetrically, comparing the mass to that of the original oil sample.

A parallel plate geometry on an ARES rheometer from TA Instruments (New Castle, DE, USA) was used to measure the oil viscosities. The strain was kept constant, and the frequency was varied in a range of 1–200 Hz with a gap of 0.3 mm. Ten repeats were completed per decade (results shown in

Table 2. WG and GB, two crude oils from the Powder River Basin in Wyoming, have been shown to yield large oil recovery in coreflooding and spontaneous imbibition experiments. The refractive index indicates the content of polar components in the oil, such as asphaltenes and resins (as well as organic acids). Viscosity was measured at 25 °C.

Oil	Acid Content (Normalized Area)	Asphaltene Content (C5 wt%)	Viscosity (cP)	Density (g/mL)	Refractive Index
WG	1.2652	10.5%	105	0.92	1.5270
GB	1.3013	9.7%	90	0.91	1.5205

), which also shows data for a previously tested oil, WG. The acid values were determined through ¹H NMR on aqueous solutions obtained in partitioning experiments. Moradi et al. [36] first developed this procedure, which was used to measure acid concentration after contact with oil in this work.

The GB crude oil was selected because it is known to be quite similar to WG (from a neighboring reservoir) and showed improved recovery upon addition of an NA acid. The data for both oils regarding recovery in coreflooding experiments are as follows: WG is the oil that exhibits improved recovery upon the addition of NAs (44.5% normal to 53.2% with acidized brine [10]), and GB was used to determine the effect of acids in imbibition recovery experiments and the influence on wettability [31]. It is worth noticing that the refractive index is remarkably similar for both samples, despite the small difference in asphaltene content. This is indicative that the asphaltenes are not very different and have similar polarity in WG and GB oils. Overall, GB and WG are similar, but GB was more readily available and has been less extensively tested in the presence of NAs. Furthermore, this oil possesses additional information regarding wettability. Therefore, it was selected for these experiments to confirm that the behavior elicited by acidized brine trends across the two crude oils.

2.3. NMR Experiments

¹H NMR was employed to investigate the presence, structure, and concentration of the NAs in this study. Experiments were conducted at 25 °C using a Bruker Advance III 600 MHz instrument (Billerica, MA, USA). Chemical shifts were referenced to water as the internal standard. The spectral width was measured at 12 ppm. Since the NMR samples were low in concentration, 256 scans were collected to optimize the signal-to-noise ratio. The pulse sequence employed applies an excitation sculpting solvent suppression for one-dimensional (1D) ¹H NMR, commonly used with samples in 90% H₂O and 10% D₂O. The spectrometer was allowed to self-select its gain, which is often concentration dependent. A time domain of 32,000 points was selected. To process NA concentrations, the area of a control peak is taken to be one (1), and the area from 0–3 ppm is taken for every sample; subsequently, this area is normalized over the gain.

2.4. Emulsion Stability Determination

Emulsions, generated at a 1:1 volume ratio with GB oil and acids dissolved in a 1% Na₂SO₄ brine. Emulsification was attained via shearing using an Ultra Turrax T25 basic (IKA-Werke) homogenizer at 6500 rpm for 30 s. Emulsion homogenization was achieved by mixing fluids at 6500 rpm for 3 min, given the importance of monodispersed drops in characterizing the coalescence process.

A Bruker Biospin minispec mq20 time-domain NMR (TD-NMR) (Billerica, MA, USA) spectrometer was used to estimate the emulsion droplet-size distribution, under the assumption that the distribution was unimodal and lognormal. NMR pulsed field gradient was first used to measure unrestricted self-diffusion of molecules in liquid by Tanner and Stejskal [39]. The NMR signal is used to calculate restricted diffusion in the droplets; the computer program from Bruker Biospin (V3.00, Billerica, MA, USA) calculates the droplet-size distribution using Equation (1).

$$q_i\left(d\right)={\displaystyle \frac{1}{d\sigma \sqrt{2\pi }}}{e}^{-{\displaystyle \frac{{\left(\ln \left(d\right)-\ln \left(d_i\right)\right)}^2}{2{\sigma }^2}}}$$

(1)

This technique is favorable as it is nonintrusive and unaffected by optical density. A log-normal is assumed as an appropriate density function to describe the drop-size distribution data for water-in-oil (W/O) or oil-in-water (O/W) emulsions. Drop coalescence, and thereby emulsion stability, are inferred from time-lapse analysis of the drop-size distribution inferred from TD-NMR.

W/O emulsions were generated for 1% Na₂SO₄ solutions and for each NA solution at 1 mM. Drop-size distributions were recorded during the first hour after emulsification and once a day between 1 and 5 days, and thereafter on days 7, 10, and 14.

2.5. Rheology Experiments

Rheological experiments were conducted on an AR-G2 Rheometer (TA Instruments) using a double-wall ring. Oscillatory interfacial rheometry was used to estimate the shear interfacial moduli. This technique is highly sensitive at low frequency, when torque tends to be low. The interface stress is calculated through Equation (2).

σ(t) = γ_o[G′(ω)sin(ωt) + G″(ω)cos(ωt)]

(2)

where σ is the shear stress, γ_o is the strain, and G′(ω) and G″(ω) are the elastic (real modulus) and the viscous (imaginary modulus), respectively. Data were only collected in the linear viscoelastic region. This was estimated by conducting a strain sweep test at a pre-determined frequency on select samples.

Fixture cleaning was achieved using toluene and methanol, and then the fixture was air-dried. To remove residual material, the Pt/Ir ring was flamed prior to each experiment. Calibration was conducted for geometry, inertia, and friction before each measurement set. Each aqueous phase was filtered using a 0.45 µm SFCA filter and examined for bubbles before lowering the ring to its desired position at the interface. Next, the oil was poured on top of the brine carefully to avoid disrupting the interface. Without moving the air table, the setup was covered and allowed to run for a minimum of five days. Viscoelasticity data were collected at various times during day 1 and then once daily for the remaining time. Temperature was controlled with a Peltier plate underneath the sample holder.

2.6. Bridge Experiments

Bridge experiments are intended to determine the resilience of the interface against snap-off. The procedure was first developed by Hoyer and Alvarado [33]. The same pendant-drop system (FTA 1000, First Ten Angstroms, Newark, CA, USA) was used in this research. Details of modifications can be found in ref [29]. As in Hoyer and Alvarado’s work [33], the slenderness ratio (Λ) is defined as the bridge length (L) divided by the needle diameter (D), as shown in Equation (3). A higher slenderness ratio indicates bridge instability. For this work, Λ was kept at 2 (unit free). Time-tracked images of the snap-off process are depicted in Figure 2.

$$\mathsf{\Lambda }={\displaystyle \frac{\mathrm{L}}{\mathrm{D}}}$$

(3)

L is the length of the bridge, while D is its outer initial diameter. Images were grabbed at 60 frames/s. The neck diameter (ND), i.e., the lowest radius along the vertical axis, was tracked over time. On the other hand, the critical neck diameter (CND) corresponds to the diameter value in the last frame of a connected bridge, as shown in Figure 2. As in previous research [33], the CND/ND ratio is used here as a stability proxy. The assumption is that elastic forces are dominant over viscous dissipation [29]. After the bridge rupture, the newly formed interfaces at the needle tips retain their high curvature (sharp interface) rather than returning to a hemispherical shape, as in the cases with low viscoelasticity. This observation shows that a more elastic interface is more effective at preventing snap-off. The interfacial response was examined for the three NA-containing systems, as well as with the initial 1% Na₂SO₄ brine.

The interface undergoes two sequential processes. First, an oil bridge is created between the opposing needles, suspended in the aqueous phase, and then aged for up to one hour. As the bridge ages, interfacial reorganization takes place, and the bridge’s interfacial elasticity increases, and interfacial tension decreases. The system remains undisturbed, indicating that surface stress equals that arising from interfacial tension. Once the bridge has experienced aging, a second process is initiated. In this process, the oil phase is withdrawn steadily at a rate of 0.1 µL/s and monitored until bridge failure [33]. During this phase, the heightened elasticity of the interface contributes to extensional longitudinal and compressive circumferential surface stress. The oil’s behavior upon bridge failure provides insight into the dominant environment of the oil–water interface. An elastic break, indicative of a thick interface, results in a sharp interface without returning to its starting hemispherical surface. A viscous break reforms the oil’s initial appearance before bridge formation, as illustrated in Figure 3.

3. Results

3.1. Emulsion Stability

The drop-size distribution is characterized by a few statistical indicators. First, the median diameter provides a sense of drop size (d0) and drop volume (d3). In all measurements, d0 is consistently smaller than d3, given that small drops, while in larger numbers, contribute less to the total volume. In contrast, large-diameter drops dominate the total volume while being much lower in numbers. The second moments of the drop-size distribution, represented here by the standard deviation, σ, serve to analyze drop polydispersity. The density distribution function, calculated from the first and second moments, is exemplified in Figure 4.

Figure 4 shows that NA14 and NA18 exhibit greater monodispersity on day one than does the brine alone. NA10 emulsion is slightly more polydisperse. This indicates immediately that shearing forms emulsions differently based on the NA present, which is likely a response to differences in interface rheology. On day 14, the order changes, and NA14 and NA18 are less polydisperse than the emulsion prepared with an aqueous phase without acids. These two acids appear to yield more stable emulsions in comparison to those formulated with a low-ionic-strength aqueous phase. NA10 increases the polydispersity more so than does 1% Na₂SO₄, which leads to destabilizing emulsions. The emulsions break down over time, as shown by the increasing polydispersity and mean diameter. An overlay of each acid on day 1 compared to day 5 and day 14 can be found in Figure 5.

The increase in diameter and polydispersity over time is apparent. It is easier to note that none of the NAs stands apart. NA10 has a slightly lower size distribution on day 1 with more broadening, which is an indication of larger polydispersity. Polydispersity can be better examined by looking at mean value and standard deviation (

Table 3. Changes in polydispersity of the emulsion drop-size distribution between day 5 and day 14 for emulsions prepared with the three selected NAs and the sodium sulfate solution.

Acid	∆d3 Day 5	∆σ Day 5	∆d3 Day 14	∆σ Day 14
1% Na2SO4	1.4705	0.162	1.641	0.273
1 mM NA10	1.46	0.2345	1.65	0.3755
1 mM NA14	1.3475	0.14875	1.4425	0.259
1 mM NA18	1.5395	0.12625	1.572	0.22375

Comparison of the d₃ values for day 5 indicates a change in volume of the rank: NA18 > Na₂SO₄ > NA10 > NA14, which is different from the rank exhibited on day 14: NA10 > Na₂SO₄ > NA18 > NA14.

).

Table 3 summarizes the results for the differences among emulsions at two different times: Δx for the range 1–5 and 1–14 days, where x is either d₃ or σ. d0 is omitted as it relates closely to σ. An increasing polydispersity would likely increase the number of small drops. The ability of acids to stabilize or destabilize emulsions depends on the amount of time observed. It is worth noticing that the ability to stabilize (or destabilize) is compared only with respect to the control case (1% Na₂SO₄). As previously seen in Figure 5, NA10 emulsion seems to be somewhat more polydisperse than other emulsions, though the size distribution does not clearly show it. However, as Table 3 shows, the standard deviation is the highest value on day 5, and after 14 days, even when the mean diameter is not the largest at the beginning, it is the largest.

This change in ranking indicates that the acid structure is not the only consideration, but that its effects are a function of time. This might be an effect of the aggregation of molecular groups, which varies from acid to acid [21]. A monodisperse emulsion system showing small change in diameter over time is an example of a stable solution. An ideally unstable emulsion would show an increasing volume median diameter over time due to coalescence while increasing in polydispersity. Polydispersity is essential to prompt capillary-driven motion, as monodisperse systems exhibit no chemical potential gradient (or pressure). This leads to capillary trapping, provided the oil ganglia exceed the size of adjacent pore throats but are small enough to not be dominant over viscous drag. Therefore, on day 14, we see that NA14 and NA18 stabilize emulsions relative to the observed characteristics of emulsions with the 1% Na₂SO₄ solution. The acids tested here induce a minute alteration in diameter and polydispersity in comparison to what is observed for the case of emulsions formed with sodium sulfate alone. NA10 induces a greater increase in d3 in comparison to that induced with the aqueous phase increase in polydispersity. This implies that NA10 destabilizes emulsions. NA10 consistently exhibits the highest σ values, indicative of highly polydisperse emulsions, which results in shorter and fatter dispersion graphs than the other emulsion (Figure 4). These results suggest that the generalization that naphthenic acids “stabilize emulsions” is valid for a time less than a week, but after two weeks, the result is clearly species dependent.

3.2. Rheological Results

Rheology data are shown for each NA at a concentration of 1 mM (Figure 6). It is important to notice that the low-salinity sulfate-containing brine, in conjunction with the average asphaltene fraction in the oil, creates an interface with relatively high viscoelastic moduli before the addition of any acid. All cyclohexenes decrease the viscoelasticity of the interface. Upon the addition of acids, we see that NA18, the smallest cyclohexane examined in this work, yields the lowest elasticity. NA10, also a cyclohexane but with an attached chain, lies between NA18 and the unacidified brine. An unforeseen contrast is observed for NA14, namely that this cyclopentane considerably increases the viscoelastic moduli. The interface becomes so elastic that it appears to break, but its elasticity grows further, as if repaired. An irreparable interface, for example, if the table were jostled, shows viscoelasticity values that continue to decrease with time. The abnormalities highlighted by this result, and in the NA14 case, suggest that cyclopentane structures may mend the interface, if broken. The tan (δ) values are also given in Figure 6. The value of this ratio indicates the balance between viscous dissipation and elastic energy storage. In this sense, NA18 causes the more significant degree of elasticity decrease without lowering the viscous modulus as much. This points in the direction of an interface with more mechanical robustness, because it should be able to balance energy storage at the interface with its dissipation, which is key to avoiding brittle failure.

Brandal et al. [30] looked at various acidic structures. In their experiments the aromatic acids in the oil intercalated at the interface to interact with the water phase, but they did not discuss partitioning. Aromatic species also showed more compact interfacial packing than saturated systems. It is possible that the aromatic structures fit closely with the asphaltenes collecting at the interface from the oil side. NA10 and NA18 show similar interfacial softening behavior, as do NA14 and the 1% Na₂SO₄ brines. In this instance, every NA that decreases the viscoelastic moduli is shown to increase interfacial dampening/softening/tan (δ). Interestingly, the tan (δ) of NA14 is well overlapped with the un-acidic brine values, despite the increase in individual moduli.

Table 4. Individual NA effects on the interface compared to the brine alone. G′, the elastic modulus, G″, the viscous modulus, and their ratio, tan (δ), are shown below.

Acid Solution	Fractional G′	Fractional G″	tan (δ)
1 mM NA10	60%	78.9%	131%
1 mM NA14	151%	137%	90.6%
1 mM NA18	42%	53.5%	127%

shows the results for 1 mM fractional adjustments of each NA on the initial brine viscoelastic moduli. Gao et al. [19] concluded that adsorption of naphthenic acids generally softened or destabilized the interface, which we see in the tan (δ) value. This viscoelastic behavior typically promotes coalescence, which is assessed with the emulsion stability data that follow.

3.3. Bridge Results

Figure 7 displays the evolution of the neck diameter, including the images used for measuring the CND of unaged systems. Notably, all systems show very similar behavior during oil withdrawal and reflect inelastic behavior as evidenced by the curved shape of the bridge by the CND. These initial results show evidence that the presence of the acids does not have an instantaneous effect on the interface of the system.

Following the initial measurement, the CND was measured at multiple intervals spanning from the initiation to one hour, as illustrated in Figure 8. While distinctions between systems may typically take a day or more to become evident, it is noteworthy that these acids exert a relatively fast impact on the interface. We established one hour as a reference time, as the species exhibit statistically distinguishable behavior at this point. All NA-containing systems converge toward stability (CND = 0), and the temporal evolution of CND for various aging periods was the same for different replicates. The stabilization time for NA18 is brief, reaching a CND value close to 0 only after 30 min. The CND for NA14 is significantly lower than the corresponding value for the brine containing only 1% Na₂SO₄ and shows a steady decrease over time, evidencing the path taken to build up an elastic interface. On the other hand, NA10 appears to preserve more inelastic behavior after 30 min of aging and only starts to build up elasticity after that time. It is worth noticing that the final CND after an hour of aging for NA10 is even higher than that of the brine alone, which suggests that NA10 does not aid in building up an elastic interface.

While distinctions between systems can often need a day or more to manifest, these NAs act rapidly on the interface. This is immediately apparent when comparing NA18 with the sole presence of brine in Figure 5, despite the challenges encountered during the initial bridge formation. After one hour, the bridge exhibited very different responses in comparison to an un-aged bridge, as seen in Figure 9. It is important to notice the difference in behavior exhibited by the brine alone; the resulting CND turns out narrower after one hour of aging (Figure 9) than initially (Figure 7). We see much more shape alteration before choke-off takes place. When this happens, the aqueous phase alone induces a more inelastic response, while that of the acid is more acutely elastic. NA10, which induces more viscoelasticity with a resulting value of tan (δ) above one, is evidently distinct from the case of the aqueous phase alone. The interface is still symmetrical; however, the response is quite different, with a CND value approaching zero. Upon examination of the CND plot for the aged bridge snap-off, it becomes clear that the snap-off is delayed with both acids. We see the cyclopentane delays snap-off compared to the 1% Na₂SO₄, as expected by the increase in elasticity, and reaches much lower CND values.

The cyclohexane NA18 caused a major drop in elastic behavior, but snap-off is delayed further than in the case of the other aqueous phases. This is probably linked to the observed solid-like film on the outer portion of the bridge (Figure 10). These wrinkles on the surface and the thin film observed during the bridge collapse indicate that large viscoelastic behavior results from the formation of a thick interface that prevents its collapse. This deformation is likely beyond the linear viscoelastic regime. This interface enables a more robust bridge, lasting longer than those in the other systems (Figure 9), which provides evidence of a stronger interface. The skin is anticipated to form, but the aging time is greater than the stabilization time (CND = 0); the solid-like film is visible for NA14 after 10 min, which makes the determination of the stabilization time difficult, therefore leading to a sudden and rapid drop in the CND, as shown in Figure 8. This finding supports the notion that these selected acids are fast-acting. For 1% Na₂SO₄ and NA14, the skin was followed for approximately 24 and 12 h, respectively. This result was expected because the aging time in each of these two cases was longer than the stabilization times, and no film formation was observed for NA10 during the first 24 h.

4. Discussion: Implications for Oil Recovery

The findings in this study, along with those presented by Smith et al. [31], have been summarized in

Table 5. Summary of the four different systems from Smith et al. [31] and this work.

		Recovery		Contact Angle		Diffusion		Rheometry		Emulsion		Bridge Experiments
Chemical Name	Brine	Water Wet	Oil Wet	Water Wet	Change for Oil Wet	Water Wet	Oil Wet	Elastic Modulus	Viscous Modulus	Average Diameter	Polidispersity	Final CND/IND	Film
Sodium Sulfate	1% Na2SO4	High	Mid-High	low	mid-high	high	high	mid-high	mid-high	mid-high	mid-high	mid-high	no
3-Cyclohexane propinoic acid	NA 10	Mid-Low	low	mid-low	high	low	mid-low	mid-low	mid-low	high	high	high	no
Cyclopentane carboxylic acid	NA 14	Low	High	high	mid-low	mid-high	mid-high	high	high	mid-low	low	mid-low	no
Cyclohexane carboxyllic acid	NA 18	mid-high	mid-low	mid-high	low	mid-low	low	low	low	low	mid-low	low	yes

. This table was created to consolidate the insights derived from both investigations concerning the impact of various naphthenic acids in comparison to the 1% Na₂SO₄ brine alone. The results are categorized into four groups: high, indicating the highest value among the four systems for a specific variable; and low, representing the lowest value. Quantitative oil recovery factors over time under spontaneous imbibition experiments can be found in reference [27]. This table serves as a tool to facilitate the examination of the interrelation between recovery, wettability behavior, and interfacial properties.

First, it should be noticed that the initial wettability condition is relevant to recovery. The correlation between initial wettability and recovery is illustrated through results when the rock is initially water-wet; the aqueous phase without NA yielded the highest recovery factor under imbibition (third column in Table 5). Among the examined acids, NA18 induces the highest recovery, followed by NA14 and NA18. Conversely, under oil-wet conditions, NA14 displays the highest recovery, followed by 1% Na₂SO₄, NA18, and NA10. In fact, results from Smith et al.’s work [31] show a significant production acceleration, even when compared to recovering results with the base aqueous phase alone. This acceleration under spontaneous imbibition conditions could be a combination of contact-angle (CA) alteration, interfacial tension, and interfacial elasticity buildup. However, further examination is necessary to fully elucidate this point.

Regarding the evolution of the CA, when the rock is initially water-wet, NA14 induces the largest CA, followed by NA18, NA10, and 1% Na₂SO₄. Under oil-wet conditions, NA10 induces the most significant change in CA, followed by 1% Na₂SO₄, NA14, and NA18. Despite NA10 showing a substantial change in CA, indicating wettability alteration, it surprisingly exhibits the lowest recovery among all systems. The observed effect of NA10 underscores that wettability alteration alone does not guarantee improved recovery, emphasizing the importance of fluid–fluid interfacial properties. NA10 might be one of the best illustrations for the need for snap-off suppression, with its mid-low elastic and viscous modulus, high polydispersity, and the highest CND diameter. These results indicate that this NA lacks the capacity to induce a sufficiently high interfacial elasticity as to prevent the choke-off of oil necks in water-wet media. In contrast, NA14 promotes an elastic interface, evidenced by mid-low CND, high elastic modulus, and low polydispersity. These observations can be interpreted as an ability to favor larger oil ganglia, thereby synergistically contributing to fluid connectivity throughout the porous system under initial oil-wet conditions, enhancing recovery. However, attention must be paid to the presence of an excessively elastic interface, which could fail as the material interface can be brittle, having detrimental effects under water-wet conditions.

NA18’s behavior is intriguing, showing the lowest elastic modulus, mid-low polydispersity, and the lowest CND. This suggests that NA18 contributes to an elastic interface but remains more viscous. These results lead to contradictory behavior, namely high recovery under water-wet conditions and low recovery under oil-wet conditions. The strange behavior of NA18 might be linked to the presence of a solid-like film observed in the bridge experiment, requiring further analysis to fully understand its role in enhanced oil recovery. Considering that oil reservoirs often exhibit intermediate wet conditions, the results suggest that NA10 is not beneficial to oil recovery.

Field application requires an understanding of the combination of mechanisms that occur in parallel due to rock-fluid and fluid–fluid interactions. In this sense, the initial condition of the reservoir and the presence of polar components in the crude must be known. For oils that contain a significant fraction of polars, the use of low-salinity water can induce a robust elastic interface. However, when brittleness becomes dominant, a negative outcome arises, which requires a moderating interfacial agent. In this case, the addition of NA18 could serve this purpose, provided the medium is already strongly water-wet or at least only mildly oil-wet. On the other hand, when the rock is dominantly oil-wet, it would benefit from a combination of NA18 and NA14, offering the potential optimal conditions for enhanced oil recovery. This combination is feasible, as NA18 has exhibited solubility at higher concentrations without compromising viscoelastic properties [37]. The concentration of acid depends on factors not studied in this research, such as adsorption on the rock and acid solubility in crude oil.

An additional consideration relates to time scales. It turns out that the formation of a viscoelastic interface occurs rapidly, in a matter of minutes or a few hours, at least in bench-top experiments. Field applications should rely on either premixing with the injection water or a delivery system that enables minimization of losses to the rock. Wettability alteration probably requires a matter of days, but the actual time scale depends on diffusion mechanisms towards the interface and kinetics of wettability alteration.

5. Conclusions

The findings presented in this study allow us to draw several relevant conclusions.

1.

Firstly, improved recovery cannot be attributed to changes in either wettability or the formation of an elastic interface in isolation. Recovery results are more likely associated with a combination of these mechanisms.

2.

Our investigation shows that small cyclohexenes, i.e., NA10 and NA18, induce a decrease in viscoelastic moduli, with NA18 exhibiting a more pronounced effect, likely due to its higher water solubility and consequently less aggregation in solution.

3.

NA14 appears to heal the interface, as evidenced by viscoelasticity results and emulsion stability testing, contributing to more stable emulsions than the case of 1% Na₂SO₄. The time-dependent behavior of NA18 and NA10 reveals distinct stability patterns over the observation period. The results emphasize the crucial role of time in understanding emulsion behavior.

4.

Results suggest that an additive for enhancing oil recovery could arise from a combination of NA14 and NA18, given their natural occurrence in crude oil systems and their potential for regulation of different interfacial interactions.

5.

Coreflooding experiments are needed to corroborate that results at zero capillary number hold under dynamic conditions, which are relevant at reservoir scale.