Control of sludge formation during acidizing through the investigation of acid and oil interactions and emulsion behavior in heavy oils using low salinity water

Abstract

Acidizing is widely used to improve well productivity, but contact between hydrochloric acid (HCl) and heavy and polar components of heavy crude oils, including asphaltene molecules, can cause strong emulsions and fluid-fluid sludge that damage the heavy oil reservoir. This study investigates how combining HCl with different smart-water formulations (seawater, diluted seawater, and ion-enriched brines containing Ca²⁺, Mg²⁺, and SO₄²⁻) affects the interfacial behavior of heavy oil. In this regard, a novel series of bottle tests was conducted at 80 °C for 48 h, and the resulting oil, emulsion, and interfacial layers were analyzed. Emulsion stability, sludge mass, droplet size, viscosity, interfacial tension (IFT), SARA (saturates, aromatics, resins, asphaltenes) fractions, FTIR (Fourier transform infrared spectroscopy)-ATR (Attenuated total reflection), elemental analysis, and zeta potential were measured to link changes in asphaltene chemistry to the macroscopic oil properties. The results show that acid prepared with deionized water produced the most stable emulsion, the smallest droplets, and the highest sludge mass. Low-salinity and Ca²⁺-rich brines also promoted strong sludge formation, confirming that insufficient ionic strength allows HCl to protonate polar oil components strongly. On the other hand, Mg²⁺- and especially SO₄²⁻-rich brines greatly suppressed sludge formation (about 0.67 g), produced larger droplets, lowered IFT (29.9 mN/m), and kept more polar and heteroatom-rich asphaltenes inside the oil. FTIR-ATR and elemental analyses show that ion-rich brines preserve oxygen- and sulfur-containing functional groups within the oil phase, limiting their migration toward the oil–acid interface. In contrast, low-salinity and calcium-rich systems promote the removal and aggregation of these groups. Zeta potential measurements further support this trend, as sulfate-rich systems develop more negative surface charges and exhibit a reduced tendency for sludge-related damage. Collectively, these observations indicate that sludge formation during acidizing is governed by the ability of brine ionic composition to regulate asphaltene surface activity and interfacial charge balance. Accordingly, ion tuning, particularly through sulfate and magnesium enrichment, stabilizes asphaltenes in the oil phase and suppresses sludge generation even under strongly acidic conditions. Conversely, low-salinity and calcium-dominated fluids intensify acid–oil incompatibility by promoting asphaltene protonation and interfacial precipitation. This mechanistic insight establishes a clear scientific foundation for designing acidizing fluids that minimize formation damage, enabling a transition from empirical approaches to chemistry-driven optimization.

Introduction

Despite the global drive toward cleaner and renewable energy sources, hydrocarbons remain the dominant source of the world’s energy supply^1,2. Their high energy density, abundance, and well-established infrastructure continue to make them essential for meeting global energy demands³. Within the petroleum industry, improving well productivity remains a central goal, and acidizing has long been recognized as one of the most effective and economic stimulation techniques^4,5. Acidizing treatments enhance formation permeability by dissolving mineral scales, removing near-wellbore damage, and cleaning the reservoir rock, thereby increasing hydrocarbon flow and recovery^6–8.

Hydrochloric acid (HCl) is the most widely used acid in carbonate reservoir stimulation because of its strong reactivity with formation minerals, cost-effectiveness, and ease of handling^5,9,10. In field applications, HCl concentrations typically range from 5 to 28 wt%, with 15 wt% being the most common due to its balance between efficient carbonate dissolution and manageable corrosion risk^11,12. When injected into heavy oil reservoirs, HCl reacts rapidly with minerals, dissolving them and thereby improving near-wellbore permeability and fluid flow^5,8,13–15.

However, in crude-oil-bearing formations, direct contact between injected acids and hydrocarbons can trigger a range of undesirable phenomena, including the formation of acid–oil emulsions, asphaltene precipitation, and sludge generation, all of which can adversely affect formation permeability and post-stimulation performance^5,16,17. These effects can be attributed to interactions between the acid and natural surface-active compounds in crude oil, primarily asphaltenes, resins, and organic acids, which migrate to the oil–acid interface and stabilize dispersed droplets^18,19. While such emulsions can sometimes enhance sweep efficiency in enhanced oil recovery (EOR) processes, they are generally detrimental during acidizing, as they increase fluid viscosity, plug pore throats, and reduce permeability, ultimately hindering post-stimulation productivity^20,21.

Emulsions, in general, are mixtures of two immiscible liquids, typically oil and water, where one phase is dispersed as droplets within the other^20,22. Their stability is governed by interfacial tension (IFT), the presence of surface-active agents, and environmental conditions such as temperature and pH^20,23. During acidizing, emulsion formation is strongly influenced by the surface activity of natural crude oil constituents, which can form rigid interfacial films that resist coalescence^24,25. These films make emulsion breakdown more difficult and contribute to formation damage. Therefore, a clear understanding of the interfacial phenomena controlling emulsion formation and stability is crucial for optimizing acidizing treatments and minimizing the adverse effects of acid–oil emulsions on reservoir performance.

Acid–oil emulsions are commonly stabilized by polar crude oil components, including asphaltenes, resins, and naphthenic acids, which accumulate at the oil–water interface and create resistant interfacial layers^19,26–28. Several researchers have linked the chemical structure and polarity of asphaltenes to the formation of these stable emulsions. Yang et al. and Geneeva et al. emphasized that asphaltenes play a major role in controlling interfacial tension and rich in heteroatoms such as sulfur and oxygen preferentially migrate to the oil-acid interface^29–31.

In two separate studies, Hou et al. showed that gemini surfactants enhance oil recovery by markedly decreasing the interfacial tension, reducing contact angle, and facilitating the formation of stable oil–water emulsions^32,33. Kalhori et al. found that the higher concentration of oil components including asphaltene led to more sludge¹⁹. Similarly, O’Neil et al. noted that these heteroatoms promote asphaltene accumulation at interfaces, leading to thick sludge layers³⁴. Poteau et al. further demonstrated that the pH of the aqueous phase alters asphaltene surface activity, indicating that both acidic and alkaline environments can enhance their interfacial behavior through protonation or ionization of functional groups³⁵.

Emulsion stability is controlled not only by the chemical interactions occurring at the oil–water interface but also by a range of operational and environmental parameters, including temperature and acid concentration^32,36–38. These factors can significantly influence interfacial film strength, droplet coalescence behavior, and reaction kinetics, ultimately determining whether emulsions remain stable or readily break under acidizing conditions³⁹. Ismail et al. observed that increasing temperature generally reduces the stability of water-in-oil emulsions⁴⁰, while Hedayati et al. reported that, in acid-oil systems, higher temperatures can increase stability due to accelerated reactions between hydrogen ions and asphaltenic compounds⁴¹. Abbasi et al. additionally demonstrated that the oil polarity considerably affects the stability of HCl-crude oil emulsions¹².

Several earlier studies have investigated the role of acid composition, ionic content, and crude oil properties in emulsion behavior. Al-Mubarak et al. demonstrated that the presence of ferric ions in acid solutions can promote asphaltene aggregation and sludge formation, leading to more stable emulsions⁴². Abbasi et al. found that the effect of pH on emulsion stability was less significant than that of ferric ion concentration, but emphasized that pH variations alter the degree of protonation of asphaltenes and resins, indirectly affecting film structure^43,44.

While these studies provide valuable insights, most have focused on acid–oil or water–oil systems using either deionized or formation water^45,46. The effect of brine salinity and ionic composition, particularly in the context of low-salinity water (LSW), remains insufficiently understood. In real field conditions, acids are often prepared using seawater or produced brine rather than pure water^47,48. The salinity and the type of ions present, Na⁺, Ca²⁺, Mg²⁺, and SO₄²⁻, can significantly alter the interfacial behavior of asphaltenes⁴⁹. Recent studies have confirmed that ion-tuned and low-salinity brines significantly alter interfacial properties and emulsion behavior under reservoir condition.

For example, Balavi et al. and Mahdavi et al. in different works demonstrated that increasing ionic strength in water–oil emulsions enhances emulsion stability by compressing the electrical double layer and reducing interfacial repulsion^20,50. Conversely, Wang et al. and Zhao et al. showed that reducing brine salinity can destabilize emulsions and modify rock wettability, which has been beneficial in enhanced oil recovery^51,52. Additionally, Cheng et al. investigated low-salinity water injection in tight reservoirs and clarified that extremely low salinity is the primary factor influencing interfacial behavior⁵³. Mahdavi et al. investigated the effect of low-salinity water on emulsion stability and reported that moderate salinity improved the stability of emulsions, whereas very low salinity reduced their stability^49,54. However, when ion-tuned water is mixed with strong acids like HCl, the ionic strength, pH, and speciation change simultaneously, producing complex interactions that remain poorly characterized.

The present study aims to address this gap by providing a comprehensive evaluation of the synergistic effect of HCl and ion-tuned seawater on asphaltene behavior in heavy crude oil and emulsion stability. Unlike previous studies that considered acid or brine effects independently, this work simultaneously investigates their interaction to better represent realistic field acidizing conditions. A novel experimental methodology was developed using an integrated suite of techniques, including emulsion stability analysis, SARA characterization, interfacial tension measurements, FTIR-ATR spectroscopy, elemental analysis, viscosity profiling, and zeta potential measurements. The main contributions of this study are as follows: (i) A systematic investigation of the combined effects of hydrochloric acid and ion-tuned seawater on acid–oil emulsion stability under conditions relevant to field acidizing operations. (ii) A detailed assessment of the influence of salinity level and ionic composition on asphaltene interfacial behavior using complementary physicochemical characterization methods. (iii) The identification of links between asphaltene structural evolution and sludge/emulsion formation, providing practical insights for mitigating formation damage during acidizing treatments.

Materials and methods

Materials

Crude oil sample

In this work, a sample of heavy crude oil was used to study the behavior of its main components. The sample’s composition is listed in Table 1. The Colloidal Instability Index (CII), used to assess the stability of oil components, was calculated using Eq. (1), and the results are presented in Table 1.

Table 1.

Summary of the key properties of the crude oil selected for the experimental evaluation.

Crude oil Properties (unit)	Density @25oC (g/cm3)	Asphaltene (%mass)	Resin (%mass)	Saturates (%mass)	Aromatic (%mass)	CII
Result	0.95	11.48	10.80	45.73	31.99	1.33

1

Additionally, Table 2. presents the carbon number distribution of the heavy crude oil sample.

Table 2.

The carbon number distribution of heavy oil sample.

Carbon No.	Mol percent (%)	Carbon No.	Mol percent (%)
C2	0.00	C19	1.26
C3	0.16	C20	1.49
iC4	0.00	C21	1.99
nC4	0.85	C22	1.73
iC5	0.00	C23	1.10
nC5	3.48	C24	1.38
C6	6.03	C25	1.02
C7	7.18	C26	0.93
C8	8.03	C27	1.34
C9	8.31	C28	0.79
C10	8.16	C29	0.10
C11	7.44	C30	0.53
C12	3.99	C31	0.75
C13	4.85	C32	0.66
C14	3.31	C33	0.78
C15	3.22	C34	0.29
C16	3.18	C35	0.66
C17	3.02	C36+	10.26
C18	1.73	Total	100

Aqueous phase

To prepare the acidic solutions, 28% hydrochloric acid (HCl) was diluted with distilled water to reach a 15% HCl concentration. Several types of smart water samples and formation water were then prepared and combined with the acid. Seawater sample representative of Arabian Sea chemistry served as the baseline fluid for the preparation of smart water phases. These included: synthetic seawater (SW), a diluted version of it (SW2d) with half the salinity; and three modified seawater samples enriched separately with calcium (4Ca), magnesium (4Mg), and sulfate ions (4SO4), each having four times the concentration of the corresponding ion in the base seawater. It is important to note that, in preparing the smart water, the seawater was first diluted twofold before increasing the concentration of the active ions. The detailed chemical properties of all solutions are presented in Table 3. All acids and salts used in this research were analytical grade (purity > 99%) and supplied by Merck, Germany.

Table 3.

Key constituents and concentrations of the synthetic smart water mixtures.

No.	Solutions	NaCl (g/L)	Na2SO4 (g/L)	CaCl2 (g/L)	MgCl2.6H2O (g/L)	KCl (g/L)	TDS (ppm)
1	(SW + HCl)	23.945	4.121	1.166	9.532	0.925	39,689
2	(SW2d + HCl)	11.975	2.060	0.583	4.766	0.462	19,844
3	(4Ca + HCl)	11.975	2.060	4.664	4.766	0.462	23,927
4	(4Mg + HCl)	11.975	2.060	0.583	38.128	0.462	53,203
5	(4SO4 + HCl)	11.975	16.484	0.583	4.766	0.462	34,270
6	Formation water	159.36	0.152	21.58	2.46	0.001	183,553

Method

Sample preparation

A series of bottle tests was designed and conducted to investigate the effects of exposure to various acid formulations on crude oil behavior and emulsion and sludge formation (oil-acid mixture), simulating fluid–fluid interactions in the reservoir. Each experiment followed a controlled, multi-step procedure.

Initially, 50 cc of the selected acid solution was carefully measured and transferred into a clean test tube. An equal volume of crude oil (50 cc) was then slowly introduced to achieve a balanced 1:1 volume ratio. This proportion was determined through preliminary experiments and supported by findings in previous research, as it provided stable phase behavior and sufficient contact between oil and acid without significant dilution. The prepared samples were subsequently mixed using a magnetic stirrer at 400 rpm for 15 min to achieve thorough dispersion and promote close interaction between the two liquid phases.

Following mixing, the samples were sealed and kept in an oven at 80 °C for 48 h, simulating the thermal environment of a reservoir. After 48 h of incubation, visual inspection revealed a distinct interfacial layer forming between the oil and aqueous phases, in addition to the clearly separated top and bottom layers. For subsequent characterization, samples were extracted separately from the upper crude oil phase and the newly developed interfacial (third) layer.

Evaluation of droplet size and diameter of emulsion

Once the emulsions were formed, a small amount from each tube was carefully transferred onto individual glass slides. The samples were then imaged using a high-resolution microscope. Special attention was given to minimize any disturbance during handling, and the spherical shape of the droplets was verified under the microscope prior to capturing images. All micrographs were taken at a constant magnification to maintain consistency and ensure clear visualization of the droplets¹². The photos were then imported into ImageJ, converted to millimeters, and finally reported in micrometers. All measurement was repeated at least three times.

Determination of fluid-fluid sludge weight

To quantify the amount of asphaltenic fluid-fluid sludge generated during the acid–oil interaction, the emulsion-rich and interfacial layers, where fluid-fluid sludge typically accumulates, were carefully collected for separation and analysis. The sludge fraction was isolated by filtering the mixture through a stainless-steel sieve, allowing only the water-insoluble solids to remain on the filter. These retained particles were washed thoroughly with hot distilled water to remove any remaining brine or acid, and subsequently rinsed with n-heptane to eliminate trapped oil. The cleaned solids were dried in an oven at 80 °C until a constant weight was obtained.

The final mass of the dried material was measured using an analytical balance and reported as the sludge mass relative to the initial oil volume¹⁹. This gravimetric approach enabled consistent comparison among all samples. Each measurement was conducted in triplicate to ensure reproducibility, and the reported values correspond to the mean of these runs, accompanied by their standard deviations.

Interfacial tension (IFT)

Interfacial tension measurements were performed using the pendant drop method, a widely accepted and precise technique for characterizing the interfacial behavior of crude oil systems²⁰. A drop shape analyzer equipped with a high-resolution camera was used to capture the geometry of a pendant oil droplet suspended in an aqueous phase, and the IFT was calculated. To isolate the effects of acid and salinity exposure on the oil phase, all IFT measurements were conducted using distilled water as the surrounding medium. This ion-free aqueous phase provided a consistent and controlled environment, ensuring that any changes in measured IFT reflected chemical modifications within the oil, particularly alterations in polarity, rather than contributions from external ions and HCl. Measurements were obtained for both crude oil and oil samples previously aged in various smart-water/acid mixtures. This allows direct comparison of how different chemical environments influenced the interfacial properties of the oil. All experiments were performed in triplicate to ensure reproducibility, and average values with standard deviations were reported.

Saturates, aromatics, resins, and asphaltenes (SARA) analysis

To evaluate how exposure to acidic and ion-rich solutions altered the composition of the crude oil, its major hydrocarbon groups were separated and quantified using a SARA-based approach. Asphaltenes were isolated first by adding an excess amount of n-heptane to the oil, causing the heaviest and least soluble molecules to precipitate⁴⁹. The resulting solid phase was collected and dried, providing the asphaltene fraction.

The remaining liquid portion, containing saturates, aromatics, and resins, was further resolved using a packed chromatographic column. This column was flushed with a sequence of solvents that increased gradually in polarity, allowing each group of hydrocarbons to elute in a controlled and distinguishable manner. Non-polar saturates were released first, followed by aromatics, and finally, the more polar resin molecules. This stepwise procedure allowed a clear determination of the relative proportions of these fractions shifted after the oil interacted with different acid–brine environments⁴⁹. All fractionation steps were repeated to ensure consistency, and the average values were used for interpretation.

FTIR-ATR spectroscopy

Infrared spectroscopy was used to investigate the changes in the chemical structure of the crude oil after exposure to acid solutions and ion-modified brines. The measurements were carried out using an FTIR-ATR instrument, which allowed direct analysis of small oil droplets without additional preparation. Each spectrum was collected over the 400–4000 cm⁻¹ range to capture the major vibrational bands associated with hydrocarbon functional groups. Particular attention was given to absorptions linked to alkyl chains, aromatic rings, carbonyl species, and hydroxyl groups, as shifts or intensity changes in these regions reflect alterations in polarity and molecular interactions induced by the different treatment conditions^49,54. The resulting spectra were compared across all samples to identify trends in chemical modification, and a summary of the key band assignments used for interpretation is presented in Table 4.

Table 4.

Identification of functional groups associated with the observed FTIR spectral peaks^49,55–57.

Wavelength (cm− 1)	Functional group
3440–3700	Free O-H (Alcohol group)
3150–3420	O–H stretch in Alcohol or Carboxylic acid, N–H stretch in Amines
3000–3150	C–H stretch in aromatic
2930–3000	CH3 asymmetric stretch
2865–2930	CH2 asymmetric stretch
2790–2865	CH2 symmetric Stretch
1650–1720	carbonyl C = O stretch
1570–1650	aromatic C = C stretch
1380–1570	C–H bend or scissoring in Alkane
1345–1380	C–H rock in Alkane
1240–1320	C-O stretching
1053–1240	C-O-C stretching in ether
920–1053	Stretching of S = O bond in sulfoxides
750–920	C-H bending in aromatic ring
650–750	C-H in long chain alkane

Elemental analysis

The asphaltene fractions isolated through SARA analysis were subjected to elemental characterization to determine their primary structural elements (C, H, S, N, and O). The results of this analysis are presented in Fig. 1.

Fig. 1.

Chemical element distribution within the examined asphaltene fractions.

Viscosity

The viscosity of the crude oil samples, including both oil and those aged in the various acid–brine mixtures, was determined using a rotational rheometer equipped with a temperature-controlled measurement system. Prior to each test, the oil was allowed to equilibrate to room temperature and gently homogenized to avoid entraining air. A small volume of the sample was then loaded into the rheometer geometry, and viscosity was recorded at 25 °C under a controlled shear-rate sweep to ensure accurate characterization of the flow behavior. Each sample was tested in triplicate to verify repeatability, and the mean viscosity values were used for analysis.

Zeta potential

The electrokinetic properties of oil droplets dispersed in aqueous media were evaluated using zeta potential analysis to elucidate interfacial charge behavior relevant to emulsion stability and fluid–fluid interactions. Measurements were conducted for both fresh and thermally conditioned crude oil systems to capture the impact of aging on surface charge development. All experiments were performed at ambient pressure and a controlled temperature of 25 °C to ensure consistency across datasets. For each condition, measurements were conducted in triplicate, and the reported values represent the arithmetic mean.

Preparation of samples

Oil–water dispersions were prepared following a modified laboratory protocol designed to ensure reproducible droplet formation and stable suspensions:

Emulsion Preparation: An oil‑in‑water dispersion containing 1 wt% crude oil was formulated using deionized water as the continuous phase. This concentration was selected to provide sufficient signal strength while minimizing multiple scattering effects during electrokinetic measurements.

Dispersion Enhancement: The prepared mixtures were subjected to ultrasonic agitation for 60 min to promote uniform droplet size distribution and to disrupt weakly associated aggregates.

Thermal Conditioning: To simulate reservoir‑relevant thermal exposure, the emulsions were placed in a convection oven and maintained at 80 °C for 72 h. This step allowed for physicochemical alterations of polar oil fractions that influence interfacial charge behavior.

Electrokinetic Analysis: Following thermal conditioning, samples were cooled naturally to room temperature prior to analysis. Zeta potential measurements were then performed to quantify the surface charge characteristics of dispersed oil droplets and assess their electrostatic stability in the aqueous environment.

A schematic illustration of the experimental workflow used for zeta potential determination is provided in Fig. 2.

Fig. 2.

The procedure used to determine zeta potential.

Results and discussions

All experiments were conducted under carefully controlled conditions, with temperature, pressure, sampling, and analytical procedures maintained at constant levels. This ensured that any changes observed were the direct result of chemical interactions driven by variations in acid and salinity, rather than experimental fluctuations. Each measurement was repeated three times, and the values reported represent the mean of these independent runs. The close agreement among the replicates confirms that the data are both consistent and highly reliable.

Emulsion and fluid-fluid sludge

Sludge formation and emulsion development during acidizing are critical concerns in reservoir stimulation because they can block pore pathways, reduce permeability, and impede oil productivity^15,19,58. These effects are governed by how crude oil components, particularly asphaltenes and resins, interact with acids and ions. To examine these interactions, crude oil was contacted with HCl solutions containing different salinity levels and ion compositions. Sludge mass, total droplet count, and mean droplet diameter were measured to assess the severity of emulsification and solids formation (Figs. 3 and 4).

Fig. 3.

Measured sludge mass formed after contacting crude oil with the brine + HCl mixture.

Fig. 4.

Microscopic images and corresponding water-droplet distribution in the (a) emulsion-(DI+HCl), (b) emulsion-(SW+HCl), (c) emulsion-(SW2d+HCl), (d) emulsion-(4Ca+HCl), (e) emulsion-(4Mg+HCl), and (f) emulsion-(4SO4+HCl).

As shown in Figs. 3 and 4, the emulsion prepared with (DI + HCl) produced the greatest number of water droplets (approximately 532) and the highest sludge mass (1.35 g). In comparison, the emulsions formed with the various brine–acid systems exhibited lower but distinguishable amounts of sludge and total droplet counts. Specifically, the sludge masses and total droplet numbers were as follows: (SW2d + HCl: 1.08 g of sludge and ~ 462 droplets)> (4Ca + HCl: 0.97 g of sludge and ~ 413 droplets)> (SW + HCl: 0.82 g of sludge and ~ 374 droplets)> (4Mg + HCl: 0.75 g of sludge and ~ 335 droplets)> (4SO4 + HCl: 0.63 g of sludge and ~ 303 droplets).

The (DI + HCl) system exhibited the most severe conditions, producing 1.35 g of sludge and over 532 droplets with a small mean size of 17.7 μm. This aligns with previous studies showing that, in ion-free acidic environments, polar oil components undergo extensive protonation, lose solubility, and rapidly aggregate, forming dense sludge and highly stable emulsions. The combination of small droplet size and high droplet count confirms strong interfacial rigidity and elevated emulsion stability.

In contrast, the presence of ions moderated these effects to varying degrees. The (SW + HCl) sample generated 0.82 g of sludge and 374 droplets with a mean size of 26.5 μm, indicating lower emulsion stability (Figs. 3 and 4). In this case, the mixed ionic environment, especially divalent cations such as Ca²⁺ and Mg²⁺, partially suppressed the HCl-induced accumulation of polar oil components at the oil–water interface. Therefore, it generated a weaker interfacial film and a less pronounced emulsification behavior.

Diluting seawater reduced this stabilizing effect. The (SW2d + HCl) sample produced 1.08 g of sludge and 462 droplets (22 μm mean size), approaching the behavior of (DI + HCl). With fewer stabilizing cations present, HCl more effectively interacts with polar oil components, increasing accumulation and promoting the formation of numerous smaller, highly stable droplets. This indicates that insufficient ionic strength enhances both sludge formation and emulsion stability.

Among ion-enriched seawater systems, (4Ca + HCl) created 0.97 g of sludge with 413 droplets averaging 23.8 μm, demonstrating moderate stabilization. Ca²⁺ ions promote bridging between negatively charged polar oil components, facilitating HCl interaction while partially limiting excessive protonation. As a result, sludge formation is lower than in (DI + HCl) and (SW2d + HCl) systems but higher than in Mg²⁺- and sulfate-enriched solutions.

According to Figs. 3 and 4, the (4Mg + HCl) sample produced noticeably less sludge (0.75 g) and fewer droplets (335 droplets, 28.9 μm mean size) than Ca-enriched emulsions. Mg²⁺, due to its smaller ionic radius and stronger hydration shell, competes more effectively with H⁺ at the interface, reducing acid reactivity with polar oil components. This leads to larger droplets and a less stable emulsion.

The weakest response occurred in (4SO4 + HCl), generating only 0.63 g of sludge and 303 droplets with the largest mean size (31.1 μm), as reported in Figs. 3 and 4. Sulfate ions act as potential-determining anions, interfering with the association of polar oil components and limiting both aggregation and interfacial film formation^49,59,60. Consequently, emulsion stability is significantly reduced, and sludge production is minimized.

Comparing the ion-enriched systems, (4Ca + HCl), (4Mg + HCl), and (4SO4 + HCl), clarifies the role of each ion in modulating HCl interaction with polar oil components. In the (4Ca + HCl) system, Ca²⁺ ions strongly interact with negatively charged regions of polar oil components, enhancing localized aggregation. However, HCl can protonate these polar groups, leading to moderate sludge formation.

In (4Mg + HCl), Mg²⁺’s competition with H⁺ limits HCl access, keeping polar components more dispersed and reducing sludge and emulsion stability. Finally, (4SO4 + HCl) shows the lowest sludge and droplet count, as sulfate ions inhibit aggregation and reduce HCl-induced destabilization.

To better clarify the role of polar oil components and their molecular structure in influencing oil properties, emulsion stability, and sludge formation, the following sections were included.

SARA

In this section, the influence of oil composition in the interfacial phenomena was investigated using SARA analysis, and the results are presented in Fig. 5.

Fig. 5.

Composition of saturated, aromatic, resin, and asphaltene (SARA) fractions in the oil after exposure to various (brine + HCl) sample.

Asphaltenes and resins make up the polar fraction of crude oil, but they behave very differently when exposed to acids and ion-containing brines. Asphaltenes are large, complex molecules with multiple aromatic rings and heteroatomic functional groups^50,61,62, which makes them highly reactive and prone to surface interactions during emulsion formation. Resins, on the other hand, have smaller and more flexible molecular structures and are generally more stable in the oil phase^63–66. Owing to these structural differences, resins tend to remain dissolved in the bulk oil, whereas asphaltenes are significantly more sensitive to chemical changes at the interface. This behavior is clearly reflected in the SARA analysis results.

As shown in Fig. 5, the resin content remained nearly constant for all treated samples, confirming that resin molecules did not participate significantly in the reactions with HCl or brine components. Their stability in the oil phase limits their migration toward the interface, so no meaningful changes were detected regardless of the solution chemistry.

The asphaltene fraction, however, showed a noticeable increase in all treated oils compared to the crude oil. The strongest change occurred in the (DI + HCl) sample, where the asphaltene content increased to 7.88%. This rise suggests that, in the absence of ions, HCl was able to react more aggressively with the polar sites of asphaltenes, promoting their aggregation and partial precipitation. Once these heavy molecules agglomerate and some are removed as sludge, the remaining oil becomes relatively enriched in asphaltenes.

In the ionic systems, the degree of change varied depending on the type and concentration of ions present. Oils contacted with (SW + HCl) and (SW2d + HCl) showed asphaltene contents of 9.73% and 8.45%, respectively. The higher value in full-strength seawater suggests that the mixed ionic environment affected the balance between destabilization and stabilization of asphaltenes, leading to moderate aggregation. The (4Ca + HCl) and (4Mg + HCl) samples displayed different behaviors: Ca²⁺ tended to enhance localized aggregation (9.19%), while Mg²⁺, which interacts differently with polar groups, resulted in a slightly higher asphaltene content (10.27%), as illustrated in Fig. 5. The highest change was observed for the (4SO4 + HCl) sample (10.81%), indicating that sulfate ions strongly influence how asphaltenes reorganize during acid contact.

Interfacial tension

Interfacial tension (IFT) experiments were carried out to examine how exposure to combined smart water and acidic environments alters the polarity and chemical composition of the crude oil after the aging process. The stabilized IFT results for all oil samples are reported in Fig. 6.

Fig. 6.

Measured interfacial tension of the oils subsequent to aging.

As shown in Fig. 6, all acid-treated oil samples exhibited higher IFT values compared to the original crude oil, which had an initial IFT of 25.7 mN/m in distilled water. Among the tested samples, the IFT values followed the general trend: (SW2d + HCl) (38.2 mN/m) > (4Ca + HCl) (36.6 mN/m)> (SW + HCl) (34.1 mN/m)> (4Mg + HCl) (32.5)> (4SO4 + HCl) (29.9 mN/m). The increase in IFT indicates that the oil became less surface-active after exposure to the acidic brine solutions. In simple terms, the treatment made the oil less capable of spreading or interacting with water, implying that some of its natural surfactants (such asphaltene molecules) were altered or aggregated. As described in Sect. 3.1, asphaltene molecules preferentially accumulate at the oil–water interface; therefore, variations in their structure or concentration tend to increase the interfacial tension.

When crude oil comes into contact with hydrochloric acid, several chemical and physical reactions take place at the molecular level. HCl can protonate functional groups such as nitrogen- and oxygen-containing species in asphaltene fractions⁶⁷. This protonation reduces the solubility of these molecules in the oil phase and often triggers their aggregation or precipitation. Asphaltene clusters become larger and less mobile, leading to fewer active sites available at the oil–water interface. Consequently, the surface concentration of polar, surface-active molecules decreases, and the measured IFT increases.

The ionic composition of the base water used to prepare the acid solutions played a decisive role in determining how much the IFT of the aged oil increased. The effect of ions at the oil–water interface on emulsion behavior can be largely explained by changes in the electric double layer thickness and salinity²⁰.

At low salinity, the electric double layer at the interface expands, which facilitates the salting-in effect^37,49. This expansion increases the interaction of the polar components of the oil with the interface, stabilizing the emulsion. In contrast, at high salinity, the electric double layer is compressed, favoring the salting-out effect⁴⁹.

This reduces the affinity of the polar oil components for the interface, leading to decreased interfacial stability. These phenomena are clearly reflected in the interfacial tension (IFT) measurements, which show lower IFT at low salinity due to enhanced interfacial adsorption of polar oil components, and higher IFT at high salinity when the interfacial interactions are weakened. The oil samples that had been exposed to higher-salinity brines exhibited slightly lower IFT values than those treated with more diluted solutions.

For example, the oil aged in (SW + HCl) showed an IFT of 34.1 mN/m, whereas the oil aged in (SW2d + HCl) reached 38.2 mN/m. This difference demonstrates that the ions present in saline water, especially divalent cations such as Ca²⁺ and Mg²⁺, act as partial stabilizers during the acid–oil interaction. These cations can form ionic bridges with negatively charged sites on asphaltene molecules, thereby retaining these surface-active species near the interface and preventing their complete destabilization or removal⁶⁸. The interface in the (SW + HCl) sample retains more polar molecules, which helps moderate the increase in IFT compared to less saline or deionized systems.

Nevertheless, the (SW2d + HCl) sample contained a lower concentration of active cations, which meant fewer stabilizing interactions and greater participation of HCl in reactions with the oil. With less ionic buffering, the acid could considerably protonate polar functional groups in the asphaltene fractions. This enhanced reaction led to stronger aggregation and migration of these polar components toward the oil–acid interface, depleting them from the oil’s bulk phase. As a result, the concentration of surface-active molecules available to stabilize the oil–water boundary decreased, and the measured IFT rose sharply. The higher IFT in the oil in contact with the (SW2d + HCl) system, therefore, reflects the greater chemical reactivity of the acid in the absence of sufficient stabilizing ions.

A comparison with the (DI + HCl) system further supports this interpretation. In deionized water, the HCl interacts freely with the crude oil components. This condition produced the highest IFT value (40.4 mN/m) among all samples, confirming that the complete absence of ionic species allows maximum protonation and destabilization of asphaltene molecules. Without cationic bridges to moderate these effects, the polar fractions aggregate heavily and are largely removed from the interface, leaving a less surface-active oil phase and thus a much higher IFT.

According to Fig. 6, when the IFT was investigated for oil contacted with (4Ca + HCl) and (4Mg + HCl), the measured IFT values ranged between 36.6 mN/m and 32.5 mN/m. These values were intermediate between those obtained for (SW + HCl) (34.1 mN/m) and (SW2d + HCl) (38.2 mN/m). This consistent pattern confirms that specific ionic interactions significantly influence on the participation of asphaltene particles during acid and smart water exposure. The introduction of Ca²⁺ and Mg²⁺ ions partially mitigated the destabilizing effect of HCl by moderating the protonation of polar groups and reducing excessive aggregation of heavy components.

A closer comparison among the individual cation systems reveals notable differences in behavior. As illustrated in Fig. 6, the (4Mg + HCl) sample showed a more pronounced decrease in IFT compared with (4Ca + HCl), indicating that magnesium ions were more effective in limiting the acid’s reactivity at the oil–water interface. This can be attributed to the smaller ionic radius and higher hydration energy of Mg²⁺, which allows these ions to remain strongly solvated and occupy interfacial regions more efficiently. By competing directly with hydrogen ions (H⁺) for active sites, Mg²⁺ ions can block the access of HCl to polar functional groups in asphaltene molecules⁶⁹. As a result, fewer polar components migrate toward the interface, and more remain dispersed in the bulk oil phase. This limited migration translates into a smaller increase in IFT, reflecting a lesser change in surface polarity for the oil exposed to Mg²⁺-rich seawater with acid solutions.

On the other hand, Ca²⁺ ions, having a larger ionic radius and lower hydration energy, interact differently with the oil phase. They do not tend to form stronger ion bridges between negatively charged asphaltene particles. While this interaction still moderates the overall acid effect compared to deionized conditions, Ca²⁺ ions are less effective than Mg²⁺ in suppressing protonation by H⁺. Consequently, the (4Ca + HCl) sample exhibited a slightly higher IFT than (4Mg + HCl), suggesting that more asphaltene molecules were displaced from the bulk oil and accumulated near the interface.

When both ions were present together, as in the (SW + HCl) system, their combined effect produced an intermediate response. The mixture of Na⁺, Ca²⁺, and Mg²⁺ provided a balanced electrostatic environment, where Ca²⁺ facilitated limited asphaltene bridging while Mg²⁺ contributed to interface stabilization through competitive adsorption⁴⁹. This synergy yielded an IFT of 34.1 mN/m, lower than that of (SW2d + HCl) (38.2 mN/m) but higher than the Mg²⁺-dominant sample (32.5 mN/m), indicating moderate preservation of interfacial stability and polarity.

The lowest IFT among the treated samples (29.9 mN/m) was obtained when sulfate concentration was increased in seawater before acidification. Sulfate ions are known to compete with asphaltene molecules for adsorption at mineral and oil interfaces. Their presence may have inhibited excessive asphaltene aggregation and kept a portion of polar components dispersed. It can be concluded that some surface-active molecules remained functional at the oil–water interface, leading to a somewhat lower IFT than other acid-treated samples. Nonetheless, even this lowest value was still higher than the untreated crude oil’s 25.7 mN/m, confirming that all acid–salinity treatments increased IFT relative to the base case.

Viscosity

Viscosity analyses were carried out to determine the crude oil’s chemical and physical behavior after exposure to the presence of acid–brine combinations. Throughout the experiments, all operational conditions, such as temperature, pressure, sampling, and measurement procedures, were controlled to eliminate their influence on viscosity. This allowed any differences in viscosity to be attributed directly to the chemical effects of the salinity–HCl mixtures. The resulting viscosity values for the treated oil samples are shown in Fig. 7.

Fig. 7.

Viscosity behavior of the crude oil following aging.

As shown in Fig. 7, the viscosity of the oil exposed to different brine solutions in the presence of HCl varied widely, ranging from 259.87 to 324.72 cP, compared with 218.31 cP for the (DI + HCl) case. These variations reflect the combined influence of several factors, including the migration of asphaltene molecules or retention in the oil phase, the extent of interfacial restructuring, and the tendency of asphaltenes to aggregate. The observed viscosity trends are consistent with the patterns identified in the IFT measurements and the emulsion and sludge analyses.

When the oil was contacted with (SW + HCl), its viscosity increased to 289.15 cP, representing a moderate rise compared with (DI + HCl). This observation aligns with its intermediate interfacial tension (IFT) value of 34.1 mN/m and low sludge formation (0.82 g). Two mechanisms help explain this behavior. First, the presence of Ca²⁺ and Mg²⁺ ions in seawater reduces the effectiveness of HCl-induced protonation and compresses the electric double layer, which limits asphaltene aggregation and precipitation. Second, because fewer asphaltenes were removed as sludge, more remained dissolved in the oil, contributing to the observed increase in viscosity.

According to Fig. 7, the oil exposed to the (SW2d + HCl) sample had a lower viscosity of 259.87 cP, even though it produced more sludge (1.08 g) and smaller droplets (22 μm). This is mainly due to its lower ionic strength. With fewer stabilizing ions, HCl interacts more strongly with asphaltene functional groups, pushing more asphaltenes toward the interface, where they are removed as sludge. As more asphaltenes leave the oil, fewer heavy molecules remain in the bulk phase, so the viscosity increases less^50,70,71. This also agrees with the high IFT value for (SW2d + HCl) (38.2 mN/m), which reflects the loss of surface-active materials.

The ion-enriched brines show different effects depending on whether the added ion was a cation or an anion. The (4Ca + HCl) sample had a viscosity of 271.44 cP, between (SW2d + HCl) and (SW + HCl), as illustrated in Fig. 7. This matches its moderate sludge formation (0.97 g) and intermediate droplet size (23.8 μm). Ca²⁺ tends to form local bridges between asphaltenes, promoting some aggregation but not fully blocking protonation^16,72. As a result, some asphaltenes are removed as sludge, while others remain in the oil, leading to a moderate viscosity rise.

The (4Mg + HCl) sample reached a higher viscosity of 303.68 cP, even though it produced less sludge (0.75 g) and fewer droplets (335, with a larger mean size of 28.9 μm). This supports the IFT results, where Mg²⁺ produced one of the lower acid-treated IFT values (about 32.5 mN/m), meaning fewer polar molecules migrated to the interface. Mg²⁺ competes strongly with H⁺ for active sites, reducing HCl’s ability to destabilize asphaltenes. As a result, more asphaltenes stay suspended in the oil and build a stronger internal network, greatly increasing viscosity. In short, systems that keep more asphaltenes in the oil, rather than converting them to sludge, show higher viscosity.

According to Fig. 7, the oil exposed to the (4SO4 + HCl) sample showed the highest viscosity of all, reaching 324.72 cP. It also produced the lowest sludge (0.63 g) and the least stable emulsion (303 droplets with a mean size of 31.1 μm). These observations agree with its relatively low IFT (29.9 mN/m). Sulfate ions appear to reduce asphaltene deposition and aggregation at the interface. Instead of forming sludge or accumulating at the interface, many asphaltenes stay dispersed inside the oil. This retention of heavier polar molecules explains the strong increase in viscosity. In other words, sulfate keeps asphaltenes inside the oil, producing a thicker, more viscous residual phase even though emulsification is weaker.

FTIR-ATR

This study employed FTR-ATR spectroscopy to analyze the asphaltene fractions extracted from aged oils that had interacted with HCl in different ion-rich seawater environments solutions. The spectra shown in Fig. 8. capture the molecular alterations that occurred within the asphaltene structures during the aging process. To further clarify these structural modifications, elemental analyses were performed on the recovered asphaltene solids. The outcomes of these analyses, which provide additional insight into compositional and structural changes, are reported in Fig. 1.

Fig. 8.

FTIR-ATR spectra of (a) oil contacted with seawater and its diluted form treated with HCl, and (b) oil exposed to ion-enriched brine with HCl.

The FTIR-ATR spectra showed several clear absorption bands within the molecular structure of asphaltene. These bands function as molecular signatures, indicating the types of chemical groups present, depending on their position in the spectrum⁵⁷. In simple terms, a peak at a certain wavelength indicates that a particular bond exists in the sample. Table 3. summarizes these assignments and lists the bonds or functional groups associated with each wavelength⁵⁷. Together, these spectral features provide a clearer picture of how the asphaltene structure changed during the aging process.

Table 3. lists the main FTIR-ATR features identified for the extracted asphaltenes, highlighting the peaks linked to alkanes, aromatic groups, carbonyls, and hydroxyl functionalities. Instead of relying only on the presence of these peaks, we also used them to gain a broader view of how the molecular makeup of the asphaltenes shifted after the oils were aged. This can directly influence the emulsions’ formation and stability.

To make these comparisons more meaningful, spectral indices were defined and calculated, as can be seen in the following equations. Ratios representing the main heteroatoms in the asphaltenes (CHSNO) were also evaluated and improve the comparison^49,67. Together, these parameters allowed us to identify chemical differences among the asphaltenes obtained from each aged oil sample. The outcomes of these calculations are shown in Figs. 9, 10 and 11.

Fig. 9.

Aromaticity and carbonyl index values obtained from the spectral analysis.

Fig. 10.

Polarized aliphatic index and sulfoxide band area derived from the spectral analysis.

Fig. 11.

Measured values of the less-polar hydrocarbon index.

Carbonyl and aromaticity

The carbonyl and aromaticity indices were used to track how oxygen-containing groups and aromatic structures changed within the asphaltene molecules. The CI index reflects the contribution of carbonyl groups, while the AR index indicates how rich the asphaltenes are in aromatic rings⁵⁷. Both parameters were calculated using the relationships provided in Eqs. 2 and 3.

2

3

The peaks appearing in the corresponding spectral regions often suggest interactions between carbonyl functionalities and aromatic compounds. This implies that carbonyl groups may be attached to, or incorporated within, aromatics in the asphaltene structure, an arrangement that can increase molecular polarity by introducing oxygen-bearing groups into the aromatic system. When the peak areas for these indices decrease, it typically points to a loss or reduction of polyaromatic structures within the asphaltenes. These trends, evaluated for each sample, are illustrated in Fig. 9.

The FTIR-based aromaticity and carbonyl indices reveal how acid–brine interactions modified the molecular structure of the asphaltenes that remained in the oil after treatment. As shown in Fig. 9, the asphaltenes extracted from the (DI + HCl) system had the lowest aromaticity (0.348), but all other samples showed a marked increase, with values ranging from 0.393 to 0.566. A similar rise was observed for the carbonyl index (0.371–0.516). These increases suggest that the more polar, oxygen-containing, and structurally less condensed asphaltene fractions were preferentially destabilized and removed from the oil, mainly through sludge formation, leaving behind a population enriched in more aromatic, carbon-dense structures. In other words, the chemical fingerprint of the asphaltenes left in the oil reflects how each acid–salinity condition stripped away the more reactive polar molecules.

Clear differences appear when comparing the various brine compositions. Oils aged in (SW2d + HCl) and (4Ca + HCl) produced asphaltenes with the lowest aromaticity and carbonyl indices among the ion-containing systems. Specifically, asphaltene-(SW2d + HCl) yielded aromaticity and carbonyl values of 0.393 and 0.411, while asphaltene-(4Ca + HCl) produced 0.427 and 0.442, respectively. These lower values indicate that a larger share of the polar, oxygen-rich asphaltenes was removed from the oil, which is entirely consistent with the high sludge masses observed for both systems (1.08 g for SW2d + HCl and 0.97 g for 4Ca + HCl). Their strong emulsion stability, evidenced by high droplet counts and small droplet sizes, also supports the idea that polar asphaltenes migrated to the interface, participated in interfacial film formation, and were subsequently incorporated into sludge. As these polar fractions left the oil, the remaining asphaltenes became chemically lighter, less aromatic, and less carbonyl-rich.

A different pattern appears in the asphaltene-(SW + HCl) and asphaltene-(4Mg + HCl) systems. Their aromaticity values (0.507 and 0.533) and carbonyl indices (0.467 and 0.484) were distinctly higher, showing that fewer polar asphaltenes were removed. This observation aligns with the lower sludge masses in these systems (0.82 g for (SW + HCl) and 0.75 g for (4Mg + HCl)) as well as the weaker emulsions (larger droplets, fewer total droplets). Mg²⁺ in particular restricted HCl access to functional groups, leaving more oxygen-containing and aromatic asphaltenes dispersed in the oil. Their retention explains the higher viscosity measured in these samples, as structurally condensed asphaltenes contribute to a stronger internal network within the oil.

The most pronounced case was the asphaltene-(4SO4 + HCl) system, where the asphaltenes exhibited the highest aromaticity (≈ 0.566) and carbonyl values (≈ 0.516). This system also produced the lowest amount of sludge (0.67 g) and the least stable emulsion (303 droplets with the largest mean size). These results indicate that sulfate ions strongly inhibit the migration and aggregation of polar asphaltene fragments, causing these molecules to remain within the oil rather than depositing at the interface or contributing to sludge. The high aromaticity and carbonyl indices therefore reflect a bulk oil that retains much of its oxygen-bearing and structurally condensed asphaltene content.

The elemental analysis provides additional support for these interpretations. As shown in Fig. 1, the oxygen content of the remaining asphaltenes followed the trend:

Asphaltene-(4SO4 + HCl) (7.8%) > asphaltene-(4Mg + HCl) (7.36%) > asphaltene-(SW + HCl) (7.06%) > asphaltene-(4Ca + HCl) (6.4%) > asphaltene-(SW2d + HCl) (5.81%).

This ordering closely mirrors both the aromaticity/carbonyl indices and the sludge/emulsion behavior. Oils that produced more sludge (SW2d + HCl, 4Ca + HCl) retained asphaltenes with lower oxygen content, consistent with the removal of oxygen-rich polar fractions. In contrast, oils that produced less sludge (4Mg + HCl, 4SO4 + HCl) preserved higher proportions of oxygen-containing groups, indicating that fewer polar asphaltenes were stripped out.

Polarized aliphatic index

The polarized aliphatic index was used to evaluate the contribution of aliphatic fractions within the asphaltene structure, providing a measure of abundance of these fractions in each sample⁵⁷, as reported in Eq. 4.

4

Among the heteroatoms examined, sulfur exhibited the greatest variability, highlighting its importance in shaping asphaltene chemistry. Functional groups that contain sulfur, particularly sulfoxides (S = O), can bond to aliphatic chains and introduce polarity into otherwise non-polar regions of the molecule. This behavior is reflected by the distinct S = O transmission peak observed in Fig. 9.

Because these sulfur-bearing aliphatic segments have increased polarity, they tend to be more active at interfaces and are more likely to migrate toward the emulsion phase and fluid-fluid sludge. For this reason, a concurrent decrease in both the polarized aliphatic index and sulfur content suggests that aliphatic portions modified by sulfoxide groups were selectively drawn toward the interface during emulsion formation. The corresponding values for these two indices are illustrated in Fig. 10.

As shown in Fig. 10, both the polarized aliphatic index and A_S=O values followed a clear and consistent trend across the samples. The highest values were obtained in the asphaltene-(4SO4 + HCl) sample (polarized aliphatic index = 0.318, A_S=O = 0.499). These values gradually decreased through the asphaltene-(4Mg + HCl) (0.293; 0.478), asphaltene-(SW + HCl) (0.256; 0.450), and asphaltene-(4Ca + HCl) (0.225; 0.411) samples, reaching the lowest levels in asphaltene-(SW2d + HCl) (0.190; 0.381). This ordering reveals that the sulfate- and magnesium-enriched systems preserved the greatest proportion of oxygen- and sulfur-containing aliphatic functional groups within the asphaltenes, while the diluted seawater and calcium-rich brines promoted the strongest loss of these polar structural features.

These spectral trends closely parallel the fluid-fluid sludge formation and emulsion behavior. The asphaltene-(SW2d + HCl) and asphaltene-(4Ca + HCl) samples, those showing the lowest polarized aliphatic and A_S=O indices, also produced the highest sludge masses (1.08 g and 0.97 g, respectively) and formed the most stable emulsions (large droplet counts and small droplet sizes). This indicates that these systems were most effective in removing the polar aliphatic and sulfoxide-bearing portions of asphaltenes from the oil, as those species participated strongly in interfacial film formation and were subsequently incorporated into sludge. As a result, the asphaltenes left in the oil became chemically depleted in these functional groups, leading to the lower index values observed.

Conversely, the asphaltene-(4Mg + HCl) and especially asphaltene-(4SO4 + HCl) systems—those exhibiting the highest polarized aliphatic and A_S=O indices—were also the systems that generated the least sludge (0.75 g and 0.63 g, respectively) and the weakest emulsions (larger droplet sizes, fewer droplets). These brines limited the ability of HCl to strip polar aliphatic and sulfoxide-containing groups from the asphaltenes, allowing more of these functionalities to remain in the oil phase. This chemical retention aligns with the higher viscosities measured for these systems, as these oxygen- and sulfur-bearing groups contribute to stronger molecular associations within the oil and promote thicker, more cohesive asphaltene networks.

The elemental analysis further reinforces this interpretation. According to Fig. 1, sulfur content followed the same progression as the polarized aliphatic and A_S=O indices, with the highest sulfur levels observed in asphaltene-(4SO4 + HCl) (4.03%) and progressively lower contents in asphaltene-(4Mg + HCl) (3.55%), asphaltene-(SW + HCl) (3.23%), and asphaltene-(4Ca + HCl) (2.71%), reaching the minimum value in asphaltene-(SW2d + HCl) (2.51%). These results show that systems favoring strong fluid-fluid sludge formation (SW2d + HCl and 4Ca + HCl) removed sulfur-bearing groups more considerably, while sulfate- and magnesium-rich systems preserved the largest fraction of these functionalities within the oil.

Interestingly, although asphaltene-(4Ca + HCl) retained more sulfur (2.71%) than asphaltene-(SW2d + HCl) (2.51%), it still showed significant reductions in both the polarized aliphatic and A_S=O indices. This suggests that Ca²⁺ not only facilitated the removal of oxygen- and sulfur-bearing groups but also promoted structural rearrangements within the remaining asphaltenes, leading to a more condensed, less polar aromatic structure. This interpretation agrees with the emulsion data, where the 4Ca + HCl system produced considerable sludge and highly stable emulsions, reflecting strong asphaltene participation at the interface.

Less-polar hydrocarbon index

The less-polar hydrocarbon index represents the contribution of long, less-polar alkyl chains—mainly methylene (–CH₂–) groups—that make up a substantial part of the aliphatic framework in asphaltene particles⁵⁷. This index is derived from the C–H stretching vibrations related to CH₂ groups, which appear as distinct peaks in Fig. 9 and Eq. 5. Stronger absorption in this region typically shows the presence of longer hydrocarbon chains, pointing to a lower overall polarity within the asphaltene structure.

5

The calculated values for the less-polar hydrocarbon index are represented in Fig. 11.

Figure 11. shows that the less polar hydrocarbon index remained fairly steady across all asphaltenes obtained from oils treated with brine + HCl. In every case, these values were higher than those of the asphaltene-(DI + HCl) sample. This suggests that, when ions are present, the less polar aliphatic portions of asphaltene molecules are largely preserved inside the oil. The reason is that the acid and ions primarily interact with the more polar parts of the asphaltene structure when brine ions are available. These polar groups migrate toward the interface, participate in emulsion film formation, and are eventually incorporated into sludge.

Meanwhile, the less polar asphaltene particles tend to remain in the oil. This interpretation fits well with the patterns seen in Figs. 9, 10 and 11, where changes in aromaticity, carbonyl content, and sulfur–oxygen functionalities all pointed to a selective removal of the more reactive, polar components rather than the entire asphaltene molecule.

The asphaltene-(DI + HCl) sample behaved differently. Because it lacks ions that could buffer or compete with HCl, the acid interacted significantly with the asphaltene molecules as a whole. This promoted the migration of a broader spectrum of oil fragments, including moderately nonpolar components, to the oil–acid interface, resulting in the greatest extent of fluid–fluid sludge formation and the highest emulsion stability. As a result, the asphaltenes left in the oil showed noticeably different chemical characteristics compared with those from brine-containing systems.

The elemental analysis results support this interpretation. The asphaltenes from all (brine + HCl) systems showed very similar carbon and hydrogen compositions, indicating that their aliphatic chains partially remained intact during treatment, as illustrated in Fig. 1. These differences imply that (DI + HCl) caused deeper structural alteration, consistent with its stronger sludge-forming and emulsion-stabilizing behavior.

Together, these observations show that ions play a key protective role: they limit acid-driven disruption of the aliphatic portions of asphaltenes, while still allowing the more polar groups to interact, migrate, and aggregate. When ions are absent, HCl affects the asphaltene structure more extensively, leading to greater molecular breakdown, more sludge formation, and significantly stronger emulsions.

Zeta potential

In this part of the study, the surface charge of the oil before and after aging in the different (brine + HCl) solutions was evaluated through zeta-potential measurements. The results are depicted in Fig. 12.

Fig. 12.

Zeta potential behavior of crude oil samples after undergoing aging treatment.

As demonstrated in Fig. 12, all brine-treated oils shifted toward more negative surface charges compared with the (DI + HCl) case, which had a baseline value of − 8.9 mV. The aged oils exhibited zeta potentials ranging from − 12.8 to − 23.3 mV, with recorded values of − 16.2 mV for (SW + HCl), − 12.8 mV for (SW2d + HCl), − 14.7 mV for (4Ca + HCl), − 19.1 mV for (4Mg + HCl), and − 22.3 mV for (4SO4 + HCl).

These increasingly negative charges indicate that the brine environments allowed a larger fraction of polar, negatively charged asphaltenes to remain dispersed in the oil rather than migrating to the interface⁴⁹. This observation agrees with the trends seen in the FTIR-ATR and asphaltene structural indices (aromaticity, carbonyl, A_S=O, and polarized aliphatic), which showed that ion-containing systems, particularly those enriched with Mg²⁺ and SO₄²⁻, preserved more polar and heteroatom-rich functionalities in the oil. It also aligns with the lower IFT values measured for (4Mg + HCl) and (4SO4 + HCl), which indicated limited depletion of surface-active components.

A clear contrast appears when comparing the behavior of the individual ions. According to Fig. 12, oil samples exposed to the (SW2d + HCl) and (4Ca + HCl), which produced the least negative zeta potentials, also corresponded to the brines that generated the highest sludge masses and the most stable emulsions.

These systems removed large amounts of polar asphaltenes from the oil and incorporated them into fluid-fluid sludge, leaving behind an oil phase depleted in surface-active molecules. Their relatively weak negative charges reflect this loss. Such behavior is undesirable from an operational standpoint because high sludge generation poses a serious risk of formation plugging, increases the likelihood of skin buildup, and raises clean-up and acid spending costs. Consequently, low salinity or high Ca²⁺ concentrations, which can lead to an increase in the electric double layer (EDL) and a salting-in effect, represent higher-risk scenarios for field acidizing treatments, as they promote asphaltene precipitation and sludge formation.

On the opposite side of the spectrum, the (4SO4 + HCl) sample showed the strongest negative charge at − 22.3 mV, which is fully consistent with its very low sludge yield (0.67 g) and weak emulsion formation (largest droplets, fewest droplet counts). The FTIR-ATR results reinforce this behavior, showing that sulfate helped retain oxygen- and sulfur-containing groups and limited their migration toward the interface. From a practical standpoint, this combination is highly favorable: less asphaltene destabilization translates directly into minimal sludge, reduced risk of formation damage, and lower post-acid cleanup requirements. This underscores the potential operational advantages of sulfate‑enriched smart‑water–acid blends in acidizing treatments, particularly for asphaltenic crude oils, where fluid–fluid sludge formation is intensified.

Similarly, (4Mg + HCl) generated a significantly negative zeta potential (–19.1 mV), consistent with moderate retention of polar functional groups, low sludge mass, and limited emulsion stability. Mg²⁺ effectively competes with H⁺ and reduces acid-driven condensation of asphaltenes, allowing more polar molecules to remain suspended in the oil. This reduces near-wellbore blockages and leads to less operational damage compared with Ca²⁺-rich or low-salinity systems.

Taken together, the zeta-potential trends mirror the broader patterns observed across the IFT, FTIR, SARA, viscosity, and emulsion results. Systems that remove polar asphaltenes to the interface—such as (SW2d + HCl) and (4Ca + HCl), produce less negative zeta potentials and more formation-damaging sludge, while systems that retain these molecules in the oil, such as (4Mg + HCl) and especially (4SO4 + HCl), generate more negative zeta potentials and significantly reduced fluid-fluid sludge formation.

From an industry perspective, this means that sulfate-rich and magnesium-rich acid–brine blends pose the lowest risk of formation plugging, whereas calcium-rich and low-salinity blends represent the highest risk, potentially increasing treatment costs.

Conclusion

This study investigated how hydrochloric acid interacts with heavy oil when combined with different smart‑water formulations, with particular attention to fluid-fluid sludge and emulsion formation during acidizing. By examining acid and brine together rather than in isolation, the results provide a clearer picture of how water chemistry influences oil stability and flow behavior during stimulation operations.

1. The findings show that brine composition plays a critical role in controlling acid‑induced emulsification and sludge formation. Systems based on deionized water and low‑salinity brines intensified acid–oil interactions, leading to stable emulsions, smaller droplet sizes, and higher sludge yields. On the other hand, brines enriched with Mg²⁺ and especially SO₄²⁻ significantly weakened these effects, producing less stable emulsions and much lower amounts of sludge. This highlights the potential of tailored brine chemistry to reduce sludge‑related formation damage during acid treatments.

2. The results also demonstrate that changes in oil properties are closely linked to how polar components redistribute between the oil and sludge phases. Acid treatment generally increased interfacial tension by removing surface‑active asphaltenes from the oil–water interface. However, the presence of specific ions limited this migration and helped retain polar asphaltenes in the oil phase. SO₄²⁻‑rich brines were particularly effective in this regard, leading to higher oil viscosity and lower sludge formation, while low‑salinity systems promoted greater asphaltene loss and lower viscosity.

3. Spectroscopic and electrokinetic analyses indicate that ionic species control both the chemical integrity and surface charge of heavy oil. Low‑salinity and Ca²⁺‑rich brines facilitated the removal of oxygen‑ and sulfur‑containing functional groups. However, Mg²⁺‑ and SO₄²⁻‑rich brines preserved heteroatom‑rich structures and generated more negative surface charges. This enhanced electrostatic stabilization reduced asphaltene aggregation, helping to explain the lower sludge yields and reduced risk of pore plugging observed in these systems.

While these findings provide valuable insights, important challenges remain. The experiments were conducted under laboratory conditions, and reservoir‑scale factors such as temperature and mineralogy, may influence acid–brine–oil interactions. Future studies should therefore focus on validating these mechanisms under reservoir conditions, exploring brine-acid-mineral systems, and assessing the long‑term impact of repeated acidizing treatments.

Author contributions

Z. A: Conceptualization, Formal Analysis, Investigation, Funding Acquisition, Writing – Original Draft, Writing – Review & EditingA. B. M. A: Conceptualization, Software, Investigation, Validation, Writing – Original Draft, Writing – Review & EditingZ. K: Formal Analysis, Resources, Validation, Methodology, Writing – Original Draft, Writing – Review & EditingP. K. S: Conceptualization, Methodology, Investigation, Writing – original draft, Writing – Review & EditingO. J. A: Formal Analysis, Resources, Investigation, Visualization, Writing – Original Draft, Writing – Review & EditingK. K: Methodology, Software, Investigation, Visualization, Writing – Original Draft, Writing – Review & EditingI. M: Resources, Data Curation, Supervision, Project Administration, Writing – Original Draft, Writing – Review & EditingM. D: Resources, Methodology, Supervision, Project Administration, Writing – Original Draft, Writing – Review & Editing.

Funding

This work was supported and funded by the Deanship of Scientific Research at Imam Mohammad Ibn Saud Islamic University (IMSIU) (grant number IMSIU-DDRSP2603).

Data availability

The datasets used and/or analyzed during the current study are available from the corresponding author upon reasonable request.

Declarations

Competing interests

The authors declare no competing interests.