Amphiphobic Modification of Sandstone Surfaces Using Perfluorinated Siloxane for Enhanced Oil Recovery

Abstract

This study establishes a covalently anchored wettability alteration strategy for enhanced oil recovery (EOR) using perfluorinated siloxane (CQ), addressing limitations of conventional modifiers reliant on unstable physical adsorption. Instead, CQ forms irreversible chemical bonds with rock surfaces via Si-O-Si linkages (verified by FT-IR/EDS), imparting durable amphiphobicity with water and oil contact angles of 135° and 116°, respectively. This modification exhibits exceptional stability: increasing salinity from 2536 to 10,659 mg/L reduced angles by only 6° (water) and 4° (oil), while 70 °C aging in aqueous/oleic phases preserved amphiphobicity without reversion—supported by >300 °C thermal decomposition in TGA; confirming chemical bonding durability. Mechanistic analysis identifies dual EOR pathways: amphiphobic surfaces lower rolling angles, surface free energy (SFE), and fluid adhesion to facilitate pore migration, while CQ intrinsically reduces oil-water interfacial tension (IFT). Core displacement experiments showed that injecting 0.05 wt% CQ followed by secondary waterflooding yielded an additional 10–18% increase in oil recovery. This improvement is attributed to enhanced mobilization of residual oil, with greater EOR efficacy observed in smaller pore throats. Field trials at the Huabei Oilfield validated practical applicability: Production rates of test wells C-9 and C-17 increased several-fold, accompanied by reduced water cuts. Integrating fundamental research, laboratory experiments, and field validation, this work systematically demonstrates a wettability-alteration-based EOR method and offers important technical insights for analogous reservoir development.

1. Introduction

China’s Songliao Basin and Bohai Bay Basin are two major petroleum-rich regions of national significance, holding important positions in global oil resource distribution. As one of the world’s top ten continental superbasins, the Songliao Basin possesses significant shale oil resource potential. The Bohai Bay Basin, leading nationally in both hydrocarbon resource volume and proven reserves, carries substantial strategic importance. However, after decades of development, traditional water flooding has contributed minimally to incremental oil production. Furthermore, following polymer flooding, surfactant flooding, and alkali-surfactant-polymer (ASP) flooding, nearly half of the original oil in place (OOIP) remains challenging to recover. To further enhance recovery from conventional reservoirs, it is imperative to explore more feasible and efficient development methods to address growing energy demands.

The Daqing Oilfield primarily features sandstone reservoirs, while the Shengli Oilfield comprises a mixture of sandstone and carbonate rock types [1,2]. Furthermore, these reservoirs contain other minerals such as feldspar and clay. Over geological deposition and long-term crude oil aging processes, mineral surfaces within such reservoirs develop strongly oil-wet characteristics [3,4]. This wettability causes residual oil within rock pores to preferentially adhere to the rock surfaces, making it difficult to displace and thereby hindering EOR. Additionally, reservoir heterogeneity—closely linked to porosity distribution—poses a critical production challenge. As a key petrophysical parameter indicating storage and flow properties, porosity directly impacts residual oil distribution and displacement efficiency. Precise characterization of these pore systems is therefore fundamental for designing effective EOR strategies, as evidenced by advanced machine learning approaches that address heterogeneity challenges in porosity prediction [5,6]. This high-precision porosity characterization strengthens geological insights into residual oil distribution (Figure 1a), particularly in heterogeneous formations where low-permeability pores and oil-wet conditions worsen recovery challenges. In such complex geological settings, specific mechanisms like the Jamin effect—where interfacial tension traps oil droplets in pore throats—and dead-end residual oil; which remains isolated in disconnected pore spaces; are difficult to mobilize (Figure 1b,c). As defined by capillary pressure (Equation (1)), the combined effect of low-permeability pores and oil-wet conditions (where the contact angle θ < 90°) means the direction of the additional capillary pressure (P_C) opposes the direction of injected water during displacement. This creates significant resistance to oil displacement, posing major challenges for EOR operations.

$$P_c={\displaystyle \frac{2\sigma \cos \theta }{r}}$$

(1)

Given these reservoir characteristics, substantial research has focused on altering reservoir wettability to reduce displacement resistance and increase water injectivity, thereby improving recovery. The goal is to decrease the cosθ value to lower the capillary resistance to oil displacement. Strategies include injecting modified nanoparticles dispersed in fluids to adsorb onto rock surfaces and alter wettability or using surfactants to reduce oil-water interfacial tension (IFT), thereby improving water spreading on rock surfaces to modify wettability [7,8,9].

Nanoparticle-based fluids (nanofluids) show promise for EOR in harsh reservoir conditions characterized by high temperature and high salinity. Their strong dispersibility and stability in aqueous phases enable them to reduce IFT and alter reservoir rock wettability, thereby improving oil recovery [10]. The mechanism involves the formation of wedge-shaped film structures within the three-phase contact region, which weakens the adhesion strength of oil on rock surfaces. This effect relies on van der Waals and electrostatic forces, raising questions about the long-term stability of its performance [11,12,13]. In contrast, conventional ionic surfactants (e.g., sulfonates, quaternary ammonium salts) function primarily through electrostatic or hydrophobic interactions with organic components in crude oil. This reduces oil adhesion to rock surfaces. Additionally, their oriented arrangement at the oil-water interface lowers IFT and enhances fluid mobility for EOR. However, their effectiveness is also susceptible to degradation under harsh reservoir conditions [7,14,15,16]. Furthermore, surfactant adsorption onto rock surfaces is a critical limiting factor for sustained EOR efficiency. Achieving optimal adsorption typically requires maintaining high surfactant concentrations within the reservoir, which is often prohibitively expensive [17].

It is evident that conventional modified nanoparticles and surfactants, when used to alter reservoir wettability, often suffer from limited long-term stability due to their reliance on relatively weak electrostatic forces or physical adsorption. To overcome this limitation, chemical agents that directly react with hydroxyl groups on rock surfaces can be employed. By forming chemical bonds, these agents create stable amphiphobic (both hydrophobic and oleophobic) surfaces. This modification reduces oil-water adhesive resistance, thereby promoting the mobilization and displacement of residual oil for enhanced recovery [18].

Previous studies have established that siloxane-based interfacial modifiers can react with hydroxyl-rich inorganic surfaces, providing a foundation for customizing rock surface properties [19]. The symmetrical and stable Si-O-Si structure endows modified surfaces with strong resistance to water flushing and aging. Furthermore, Grainger et al. [20] demonstrated that in fluorinated organic compounds, the dense arrangement of strongly electronegative fluorine atoms on molecular surfaces results in extremely low surface free energy and unique amphiphobicity. These exceptional wettability-altering properties have made fluorinated compounds widely applicable in petroleum and natural gas research. Jin et al. [21] treated nano-silica with fluorosurfactant FG-40 for gas reservoir wettability modification. The surface free energy of treated cores decreased sharply from approximately 70 mN/m to 0.61 mN/m, transforming wettability from strong liquid-wetting to super gas-wetting, thereby mitigating liquid condensation-induced productivity decline in porous media. Liu et al. [22] revealed that fluorinated agent FC-1 likely reduces oil droplet adhesion work through its amphiphobic surface modification, contributing to injection pressure reduction and enhanced fluid injectivity. FC-1 also demonstrated stable oleophobic effects on oil-aged cores. Long et al. [23] employed perfluorobutyl ethanol to synthesize emulsifying fluorosurfactant EFS, proving its dual functionality: effectively altering glass surface wettability and softening residual oil to improve recovery in capillary displacement experiments. While most studies confirm the efficient and stable amphiphobicity imparted by fluorinated compounds, limitations persist. Sufficient aging resistance validation and field trial data remain scarce, with most evidence derived from laboratory experiments. Thus, the practical EOR efficacy of fluorinated agents requires further investigation.

To address this, we utilize perfluorinated siloxane (CQ) as an interfacial modifier to alter rock wettability, leveraging its exceptional amphiphobicity and low surface energy to investigate EOR. Our study encompasses four key aspects: First, a cosolvent is selected to formulate an injectable CQ solution system, with its feasibility for rock surface modification experimentally confirmed. Subsequently, the salt resistance, thermal tolerance, and aging stability of CQ-modified rock wettability are evaluated, while the mechanistic basis for EOR via wettability alteration is analyzed. Following this, the EOR performance of the CQ system is quantitatively assessed through core-scale displacement experiments. Ultimately, a field trial conducted in the Huabei Oilfield (PetroChina, Renqiu, China) provides comprehensive validation of its applicability under actual reservoir conditions.

2. Materials and Methods

2.1. Materials and Instruments

The CQ solution was prepared by mixing perfluorinated siloxane interfacial modifier CQ, sodium dodecylbenzenesulfonate (SDBS, Macklin Biochemical Co., Ltd., Shanghai, China), ethanol, and acetic acid (all purchased from Chengdu Chron Chemicals, Chengdu, China) at specified ratios. All chemicals were of A.R. grade.

Crude oil samples were obtained from the Huabei Oilfield. At reservoir conditions (70 °C), the oil exhibited a viscosity of 87.5 mPa·s and a density of 0.8499 g·cm⁻³. Hydroxy silicone oil (Hydroxyl Value < 3.0%, Bide Pharmatech Ltd., Shanghai, China) was used for aging experiments.

Formation water was employed for both thermal stability and aging tests. According to reservoir data, this formation water contains negligible Mg²⁺ and SO₄²⁻. Simulated formation waters with varying salinities were prepared using KCl, CaCl₂, NaCl, and Ca(HCO₃)₂ (all AR grade, Chengdu Chron Chemicals). Ionic compositions are detailed in

Table 1. Chemical composition of formation water and simulated formation water.

Sample 1	Na+ + K+ (mg/L)	Mg2+ (mg/L)	Ca2+ (mg/L)	Cl− (mg/L)	SO42− (mg/L)	HCO3− (mg/L)	Salinity (mg/L)
FW	1280.5	7.3	116.2	2020.7	4.8	305.1	3734.6
SFW-1	897.8	5.6	28.9	1233.7	19.2	350.9	2536.1
SFW-2	1800.1	14.6	80.2	2729.7	19.2	372.2	5016.1
SFW-3	2190.3	13.1	76.2	3385.5	19.2	259.3	5943.6
SFW-4	2762.3	14.5	63.9	3956.2	208.6	524.7	7530.2
SFW-5	5401.2	10.1	29.0	4608.3	260.3	350.5	10,659.4

¹ FW refers to formation water; SFW-1 to SFW-5 represent simulated formation water.

.

Standard sandstone core plugs sourced from Huabei Oilfield were used for displacement experiments, while core slices were prepared for contact angle measurements. Core properties are summarized in

Table 2. Core properties in displacement experiments.

Sample	Length (cm)	Diameter (cm)	Permeability (mD)	Porosity (%)
Core-1	4.98	2.49	53	18.7
Core-2	4.99	2.49	77	18.3
Core-3	5.01	2.50	103	19.1
Core-4	5.03	2.49	146	19.5
Core-5	5.02	2.50	177	19.2

. The coefficients of variation for core permeability and porosity were 40.56% and 2.21%, respectively.

Key experimental instruments are listed in

Table 3. Experimental instruments and information.

Instrument	Model	Manufacturer
Contact Angle Goniometer	LSA100	LAUDA Scientific, Lauda-Königshofen, Germany
Scanning electron microscopy	Quanta 250 FEG	FEI Company, Hillsboro, OR, USA
FTIR spectroscopy	NICOLET IN10	Thermo Fisher Scientific Inc., Waltham, MA, USA
Thermogravimetric analysis	TGA/DSC1	Mettler, Greifensee, Switzerland
Spinning drop interfacial tensiometer	CNGTX700	Shengwei Tech., Beijing, China

.

2.2. Analytical Methods

The principal analytical methodologies employed in this study are summarized in

Table 4. Analysis methods for various experiments.

Method	Purpose	Principle	Uncertainty
Wettability Analysis	Determine the wetting preference of the core surface (oil-wet or water-wet)	A contact angle < 90° indicates water/oil-wet	±2° (contact angle measurement)
Interfacial Tension Measurement	Measure oil-water interfacial tension	Drop deformation under rotation analyzed for tension calculation	±0.01 mN/m (for low-tension systems)
Surface Free Energy Measurement	Quantify core surface free energy (related to wettability/adhesion)	Owens-Wendt method based on contact angles with probe liquids	±3%
Liquid Adhesion Work Measurement	Evaluate liquid-core adhesion strength	Young-Dupré equation	±3%
Water Flooding Equilibrium Permeability Measurement	Reflect the fluid flow capacity	Darcy’s law	±4%

.

2.3. Preparation of Modifier Solution

SDBS was first dissolved in water at 50 °C. After stirring for 20 min, the solution gradually transitioned from grayish-white to transparent, which indicated complete dissolution. The mixture was then cooled to room temperature, followed by the addition of anhydrous ethanol under continuous stirring. A small amount of glacial acetic acid was subsequently introduced to maintain a weakly acidic environment, ensuring thorough integration of all components. Finally, the interfacial modifier CQ was incorporated, and the solution was stirred for 1 h. The CQ solution was sealed and stored under ambient conditions until use.

2.4. Wettability Measurement Under Various Conditions

CQ solutions with concentration gradients were prepared using both formation water (FW) and simulated formation water (SFW) of varying salinities (SFW-1 to SFW-5). Core samples were treated with these solutions, followed by rinsing. The samples were then mounted on a stage apparatus to measure water/oil contact angles in their respective environments, assessing the wettability alteration efficacy of the modifier solutions across different salinities.

Separately, multiple solutions of the same CQ concentration were prepared using formation water. Core samples were then immersed in these solutions and aged at 70 °C for 120 days. Periodically, cores were removed, rinsed, and their contact angles measured. This provided initial insights into the temperature resistance and aging stability of the modified core’s wettability.

For each core slice, five measurements were taken on both the front and reverse surfaces. The average value was recorded as the final data point. The influence of wettability on droplet transport across core throat surfaces was preliminarily evaluated through measurements of the rolling angle, advancing angle, and receding angle. Using a tilting platform, data were recorded precisely at the critical point of droplet motion.

2.5. Spontaneous Imbibition Tests

Spontaneous imbibition tests were performed on three cores with high, medium, and low permeability (as detailed in

Table 5. Core properties in displacement spontaneous imbibition experiments.

Sample	Length (cm)	Diameter (cm)	Permeability (mD)	Porosity (%)
Core-6	4.97	2.51	21	18.7
Core-7	5.01	2.49	80	18.3
Core-8	4.99	2.50	211	19.6

) to investigate wettability effects on capillary forces. After drying to constant weight, each core was vertically suspended above a beaker containing deionized water, with its base precisely contacting but not submerged in the water surface. Water loss in the beaker was continuously monitored, while parallel blank evaporation tests under identical ambient conditions (25 ± 0.5 °C) provided compensation data. Mass reduction recorded by analytical balance (±0.001 g accuracy) was converted to water volume imbibed into pores. Enabling quantitative assessment of gas displacement efficiency and comparative analysis of imbibition intensity across wettability variants.

2.6. Surface Free Energy Measurement

To elucidate the wettability alteration mechanism induced by the fluorinated interfacial modifier CQ on core surfaces, the Owens two-liquid method was employed to quantify surface free energy (SFE) changes. The SFE of a solid surface (${\gamma }_s$) comprises dispersive (${\gamma }_S^d$) and polar (${\gamma }_S^p$) components (Equation (2)):

$${\gamma }_S={\gamma }_S^d+{\gamma }_S^p$$

(2)

Contact angles (θ) of two probe liquids with known SFE components—deionized water (polar) and n-hexadecane (non-polar)—were measured on core surfaces. The SFE components were then solved using the Owens-Wendt equations [24]:

$${\gamma }_{L1}(1+\cos {\theta }_1)=2(\sqrt{{\gamma }_S^d{\gamma }_{L1}^d}+\sqrt{{\gamma }_S^p{\gamma }_{L1}^p})$$

(3)

$${\gamma }_{L2}(1+\cos {\theta }_1)=2(\sqrt{{\gamma }_S^d{\gamma }_{L2}^d}+\sqrt{{\gamma }_S^p{\gamma }_{L2}^p})$$

(4)

Probe liquid parameters [25]: Deionized water: ${\gamma }_{L1}$ = 72.8 mN/m, ${\gamma }_{L1}^d$ = 21.8 mN/m, ${\gamma }_{L1}^p$ = 51.0 mN/m; n-Hexadecane: ${\gamma }_{L2}$ = 27.6 mN/m, ${\gamma }_{L2}^d$ = 27.6 mN/m, ${\gamma }_{L2}^p$ = 0 mN/m (negligible polar contribution). Simultaneously solving Equations (3) and (4) yields ${\gamma }_S^d$ and ${\gamma }_S^p$, thereby uncovering the physicochemical origin of wettability modification.

2.7. Oil-Water Interfacial Tension Measurement

IFT, a critical parameter governing displacement efficiency during EOR, was measured using a spinning drop tensiometer at reservoir temperature. In this procedure, a calibrated glass capillary tube was first loaded with the aqueous CQ solution, followed by injection of 1–3 μL crude oil to form a discrete droplet. Under controlled rotation (1000–20,000 rpm), centrifugal forces elongated the droplet until equilibrium morphology was attained (70 °C). To eliminate time-dependent effects on IFT, all reported data correspond to equilibrium IFT values recorded after sufficient rotation (typically 10–30 min). These IFT values were automatically calculated using computer vision algorithms that analyzed real-time droplet profiles, with triplicate measurements performed for each data point to ensure statistical reliability [26].

2.8. Water Flooding Experiment

Water-saturated core samples were first placed at 70 °C and flooded with crude oil at a constant rate until water production ceased at the outlet. Oil saturation (S_o) was determined by monitoring pressure dynamics and cumulative water production. The oil-saturated cores were then aged for subsequent testing. Following this, primary water flooding was conducted by injecting formation water, with pressure variations and effluent volumes recorded versus pore volumes (PV) injected. This enabled analysis of residual oil saturation (S_or) and primary recovery efficiency. Subsequently, 0.2 PV of CQ solution was slowly injected into the core. After sufficient reaction time at 70 °C, secondary water flooding was performed. The incremental oil recovery was quantitatively evaluated by measuring fluid production changes at the outlet.

2.9. Field Trial

To further validate the applicability of CQ under actual reservoir conditions, field tests were conducted on two pilot wells in Huabei Oilfield. The implementation followed a huff-and-puff operation protocol (

Table 6. Operational details of the huff-and-puff process.

Well	Total CQ Solution Injection (m3)	Preflush CQ Injection (m3)	Alternating Water Slug (m3)	Stage 2 CQ Injection (m3)	Alternating Water Slug (m3)	Stage 3 CQ Injection (m3)	Post-Treatment Daily Water Injection (m3/d)
C-9	2.5	0.5	60	1	100	1	20
C-17	3	1	100	1	100	1	20

), wherein formation water and CQ modifier were pumped downhole in alternating cycles. Post-injection, a designated water slug displaced the CQ solution deeper into the formation. After a 24 h shut-in period for reaction, normal water flooding resumed without additional procedures. The EOR efficacy of CQ was evaluated by monitoring incremental crude oil production during subsequent operations.

3. Results and Discussion

3.1. Characterization of Modification Reaction

FT-IR analysis (4000–500 cm⁻¹) was employed to verify the chemical bonding of modifier CQ to rock surfaces by comparing core samples with pure CQ liquid. As shown in Figure 2a, unmodified rock exhibited a distinct -OH stretching peak at 3420 cm⁻¹, indicating available surface hydroxyl groups for reaction, whereas pure CQ—a nonionic fluorocarbon surfactant—showed negligible -OH signals due to unexposed hydroxyl groups prior to hydrolysis. Characteristic fluorocarbon vibrations in CQ included C-F stretching at 1100 cm⁻¹, symmetric/asymmetric -CF₂ modes at 1210/1450 cm⁻¹, and -CF₃ stretching at 960 cm⁻¹, with both CQ and modified CQ-Rock displaying asymmetric -CH₂ stretching at 2930 cm⁻¹. Additionally, the 1410 cm⁻¹ band (-CF₂) persisted post-modification, confirming fluorocarbon retention. Collectively, these spectral transitions—diminished hydroxyl intensity; retained fluorocarbon signals; and hydrocarbon marker—confirm successful covalent grafting of CQ onto rock surfaces; directly enabling the wettability modification demonstrated in Figure 2b.

Energy-dispersive spectroscopy (EDS) was further employed to characterize elemental composition changes on core surfaces before and after CQ modification. As shown in Figure 3a, the untreated core surface primarily consisted of Si, C, O, and Ca. This elemental profile indicates the presence of calcite alongside sandstone constituents, suggesting calcite cementation within intergranular pores—consistent with typical sandstone lithology. Trace iron detected likely originated from sample contamination during preparation when iron tools contacted the surface. Figure 3b demonstrates a distinct elemental shift post-CQ treatment: Fluorine (F) is now conclusively detected, confirming successful grafting of fluorocarbon groups (-CF₂/-CF₃) onto the rock surface. This covalent bonding fundamentally alters surface properties, as evidenced by subsequent wettability measurements.

3.2. Stability of Wettability Alteration Performance

Following the initial confirmation of successful CQ modification on the core surface, this section investigates the influence of CQ concentration and solution salinity on wettability alteration efficacy, as well as the long-term stability of the modified wettability. Core slices were treated with CQ solutions prepared at varying concentration gradients and different brine salinities, with all experiments conducted under ambient room temperature. The CQ was evaluated at mass fraction concentrations of 0.005%, 0.008%, 0.01%, 0.02%, 0.05%, and 0.1%. Concurrently, the salinity gradient (mg/L) investigated included values of 2536.1, 3734.6, 5016.1, 5943.6, 7530.2, and 10,659.4 (Table 1).

The results for water and oil contact angles under each experimental condition are presented in Figure 4. On core slices treated with a 0.05 wt% CQ solution prepared in SFW-1, water and oil contact angles reached 135.1° and 116.3°, respectively, indicating effective dual hydrophobic and oleophobic effects. At this concentration, although the contact angles exhibited a slight decrease (water and oil angles reduced to 129° and 112.3°, respectively) with increasing salinity (mineralization), the overall wettability change was insignificant. This observation demonstrates that the CQ system possesses a degree of stability under formation brine salinity conditions. At the higher CQ concentration of 0.1 wt%, the improvement in contact angles was marginal. Considering both the research outcomes and application cost-effectiveness, a CQ concentration of 0.05 wt% was tentatively selected as the preliminary formulation for the system. This concentration is also employed for subsequent comparative aging experiments.

To assess the long-term stability of modification, core samples were treated with 0.1 wt%, 0.05 wt%, and 0.02 wt% CQ solutions prepared in formation water. These underwent 120-day aging under sealed conditions in formation water at 70 °C. Periodic contact angle measurements tracked changes in amphiphobic surface properties. Relevant literature indicates that under reservoir conditions with temperatures <120 °C and pressures <20 MPa, the impact of high temperature and pressure on wetting contact angles is not significant. Specifically, elevated temperatures enhance the thermal kinetic energy of water molecules, promoting their diffusion on core surfaces and thereby strengthening wettability. In contrast, increased pressure compresses the spacing between water molecules, intensifying hydrogen bonding while weakening adsorption energy with rock surfaces, which leads to reduced wettability. These two opposing effects mutually compensate for each other, effectively reducing deviations between laboratory experimental results and actual reservoir conditions, thus ensuring the representativeness of our conclusions [27,28,29].

Data (Figure 5a) show contact angles gradually decreasing with aging time. The 0.1 wt% and 0.05 wt% groups exhibited minor final reductions: the 0.05 wt% group showed water contact angles decreasing from 135° to 128° and oil contact angles from 115° to 111°. In contrast, the 0.02 wt% group displayed significantly greater reductions. This suggests an incomplete reaction between CQ and core surface hydroxyls at lower concentrations, with potentially only 1–2 of CQs three hydroxyl groups bonding effectively. This resulted in reduced stability versus higher concentrations and more pronounced oleophobicity decay, with the oil contact angle falling to 100° at 120 days. Comparatively, 0.05 wt% CQ-modified cores maintained excellent anti-aging performance, preserving oil and water contact angles of 111° and 128°, respectively, after 4-month aging.

The anti-aging performance of the amphiphobicity of CQ-modified cores in an oil phase was investigated. Core samples treated with varying CQ concentrations were aged sealed in hydroxyl silicone oil at 70 °C. Results (Figure 5b) indicate slower hydrophobic performance decline during oil-phase aging compared to water-phase aging. For 0.05 wt% CQ-treated cores, the water contact angle decreased from 137° to 132° over 120 days; declines for other concentrations were also below 10°. Regarding oleophobicity, the oil contact angle for the 0.05 wt% group decreased from 115° to 103°, showing a greater decline than in water aging, yet good oleophobicity was maintained throughout 120 days.

Thermogravimetric analysis (TGA) revealed the excellent thermal stability underlying these properties (Figure 6). The CQ-modified core exhibited an onset decomposition temperature near 300 °C and a peak decomposition temperature around 400 °C. This range significantly exceeds typical reservoir temperatures and shows superior thermal stability versus literature-reported silica nanoparticles modified with conventional surfactants (NP-10, CTAB), which decomposed near 200 °C with peaks at 245 °C and 360 °C [30]. This finding further confirms that the Si-O-Si chemical bonding of CQ is significantly stronger than traditional molecular interactions or electrostatic adsorption.

In summary, the chemical grafting of CQ onto the core surface imparts its amphiphobic properties with robust anti-aging stability in both formation water and oil. This further validates the reliability of the CQ system for field applications.

3.3. Droplet Dynamics on Amphiphobic Surfaces

Building upon the confirmed stability of amphiphobic properties on CQ-modified core surfaces, we further investigated how this characteristic influences the dynamic behavior of droplets. Dynamic contact angle measurements revealed that amphiphobic surfaces substantially enhance liquid transport across rock interfaces, directly contributing to improved oil recovery efficiency.

When testing cores treated with increasing CQ concentrations (0.005–0.05 wt%), distinct performance gradients emerged (Figure 7). At the lower 0.005 wt% concentration—indicating insufficient modification—rolling angles remained elevated at 8° for water and 9° for oil. However, when treatment concentration reached 0.05 wt%, rolling angles decreased significantly to equilibrium values of 3° (water) and 4° (oil), demonstrating a reduction in the force required for droplet movement [31]. Parallel improvements occurred in advancing (θ_a) and receding (θ_r) contact angles: water angles rose to θ_a = 143° and θ_r = 140°, while oil angles increased to θ_a = 122° and θ_r = 118°. These elevated angles confirm drastically diminished fluid flow resistance through amphiphobic core pores, thereby enhancing the mobility of both water and oil and laying the groundwork for improved EOR performance.

3.4. Spontaneous Imbibition Results

To further quantify the impact of wettability on capillary forces within cores, spontaneous imbibition experiments were conducted. Results (Figure 8) demonstrate that across high-, medium-, and low-permeability cores, unmodified samples exhibited strong hydrophilicity and significant water uptake, with denser cores absorbing greater water mass—consistent with the relationship in Equation (1). This phenomenon arises because water contact angles in unmodified pore throats are <90°, generating upward-directed capillary forces that intensify with decreasing throat radius (r), thereby spontaneously displacing pore gas through water imbibition. Following CQ modification, wettability reversal to hydrophobic shifted capillary force direction in pore throats, dramatically suppressing fluid uptake. Crucially, this effect peaked in the tightest low-permeability core (Core-6), where gas displacement efficiency plunged from 0.89% (pre-treatment) to 0.017% (post-treatment). These findings confirm that CQ-induced wettability alteration critically governs both magnitude and direction of capillary forces in pore throats, while the resultant amphiphobic surface effectively reduces liquid adhesion, thereby enhancing oil recovery during displacement processes.

3.5. The Surface Free Energy of Amphiphobic Cores

The fluorinated interfacial modifier CQ significantly alters core wettability through the grafting of low-surface-energy fluorocarbon chains onto rock surfaces. To quantify this effect, surface free energy (SFE) was calculated using the Owens two-liquid method (

Table 7. SFE data of CQ- and SDBS-Modified Core Samples.

Solution	Concentration (wt%)	Deionized Water (°)	n-Hexadecane (°)	Surface Free Energy (mN/m)
CQ	0	0	0	73.17
	0.005	85	66	23.28
	0.008	103	87	12.22
	0.01	110	96	8.83
	0.02	115	100	7.05
	0.05	124	107	4.94
	0.1	133	110	3.24
SDBS	0.005	56	0	48
	0.008	62		44
	0.01
	0.02
	0.05
	0.1

). As determined from Figure 9a, untreated cores (0 wt% CQ) exhibited water and n-hexadecane contact angles of 0°, yielding an SFE of ~73.17 mN/m. After treatment with 0.05 wt% CQ solution, contact angles increased to 124° (water) and 107° (oil), reducing SFE to 4.92 mN/m—a 93% reduction. Further concentration increases resulted in marginal additional decreases.

Notably, since SDBS was incorporated as a cosolvent in CQ formulations, control experiments with SDBS alone were conducted. Figure 9a demonstrates that SDBS-treated cores maintained substantially higher SFE than CQ-modified surfaces. This divergence stems from water contact angles plateauing near 62° at SDBS concentrations >0.008 wt% and the complete absence of oleophobicity (oil contact angle = 0°). These results confirm that the amphiphobicity originates predominantly from CQ-derived fluorocarbon chains, which demonstrate superior performance in minimizing surface energy through effective surface grafting.

According to the Young-Dupré equation, the work of adhesion (W_ls) between a solid and liquid is defined as Equation (5):

$$W_{ls}={\sigma }_l(1+\cos \theta )$$

(5)

where σ_l is the liquid surface tension (mN/m) and θ is the contact angle (°), deionized water and n-hexadecane have surface tensions of 72.8 mN/m and 27.6 mN/m, respectively. For the unmodified core (0 wt% CQ), the adhesion works of deionized water and n-hexadecane were calculated as 145.6 mJ/m² and 55.0 mJ/m², respectively. As the CQ treatment concentration increased, the SFE of the core decreased rapidly, enhancing its amphiphobicity. This resulted in a dramatic reduction in adhesion work for both liquids. At 0.05 wt% CQ, the adhesion work of deionized water dropped by an order of magnitude to 32.1 mJ/m², while that of n-hexadecane decreased to 19.5 mJ/m² (Figure 9b).

These results demonstrate that perfluorinated silane CQ modification facilitates liquid detachment from rock surfaces, significantly lowering the energy barrier for residual oil mobilization during displacement processes. Notably, these laboratory measurements were conducted under ambient conditions. In actual reservoir environments, the surface tensions of water and oil are projected to decrease further while contact angles remain largely stable. Consequently, adhesion work would be further reduced, amplifying the EOR efficacy of CQ-treated cores in field applications [32,33,34].

3.6. The IFT Reduction Performance

Previous experiments have demonstrated that wettability alteration, resulting from reduced SFE of the rock core, can modify the direction and magnitude of capillary forces, thereby promoting fluid transport within the pores. This mechanism is identified as one of the potential contributors to EOR.

To investigate whether injecting the perfluorinated silane CQ solution into the formation could reduce oil-water IFT and mobilize residual oil, further measurements were conducted. The experimental results (Figure 10) indicate that both CQ and the anionic surfactant SDBS significantly reduce oil-water IFT. However, CQ exhibits superior efficacy in interfacial activity modulation. As illustrated in Figure 10, when the CQ solution concentration increased to 0.05 wt%, the oil-water IFT decreased from an initial value of 24 mN/m to 0.81 mN/m and subsequently stabilized. This suggests that the critical micelle concentration (CMC) of CQ is approximately 0.05 wt%. In contrast, within the same concentration range, SDBS only reduced the IFT to 5.01 mN/m. The superior performance of CQ is attributed to its molecular structure: the fluorocarbon chains of CQ possess a smaller atomic radius and shorter C-F bond lengths compared to the C-H bonds in SDBS. This results in stronger tail hydrophobicity, enabling faster molecular alignment at the oil-water interface. Consequently, CQ achieves a lower IFT at lower concentrations. Furthermore, a synergistic effect between SDBS and CQ contributes to enhanced IFT reduction, allowing the CQ solution to reach lower IFT values than SDBS at reduced concentrations.

It is evident that the reduction in IFT is predominantly governed by CQ. This conclusion aligns consistently with the aforementioned SFE measurements.

3.7. Oil Displacement Performance

To investigate the improvement in EOR resulting from wettability modification of the core surface, displacement experiments were conducted on cores before and after chemical treatment. A series of cores with permeabilities ranging from 53 to 177 mD (Table 2) were used for the displacement tests.

The variations in oil recovery, water cut, and injection pressure with injected pore volume (PV) during the displacement of Core-2 are presented in Figure 11a. The results demonstrate that during the initial waterflooding stage, both the injection pressure and recovery increased with the injected volume, while the water cut remained at 0%. The ultimate water-free oil recovery reached 6%. In the mid-term waterflooding stage, the injection pressure decreased slightly, attributable to the continuous breakthrough of injected water. During this phase, an oil-water mixture began to be produced at the outlet. When the water cut exceeded 98%, the oil recovery reached approximately 45%, indicating the onset of the late waterflooding stage. Concurrently, the injection pressure began to decline slowly and eventually stabilized. After oil production ceased for a period, 0.2 PV of CQ solution was injected and allowed to react at 70 °C for approximately 4 h, followed by subsequent displacement. During the EOR phase, an increase in injection pressure was observed, serving as a definitive indicator of effective residual oil mobilization. This phenomenon arises from the CQ agent-induced reduction in oil-rock interfacial adhesion. During water flooding, the flowing injection stream detaches residual oil from pore throats, promoting the coalescence of isolated oil ganglia into continuous oil banks. Due to viscosity differences, the migration of residual oil driven by injected water generates a certain injection pressure. Furthermore, as the oil banks and injected water migrate to the branching points of pore throats, the potential formation of the Jamin effect introduces additional injection resistance, thereby causing a rise in injection pressure. Subsequently, as mobilized oil is produced at the outlet, pressure gradually declines, accompanied by reduced water cut. Ultimately, oil recovery reached 59%—representing a 14% incremental recovery. These results unequivocally demonstrate the significant contribution of the CQ system and wettability alteration to EOR performance.

In multiple sets of core flooding experiments, the influence of varying core properties on the EOR performance enhancement by CQ was also investigated. Core-1 to Core-5 exhibited a range from tight to unconsolidated properties (Table 2).

The results (Figure 11b) demonstrate that as the core became more unconsolidated, the incremental oil recovery achieved by CQ progressively decreased (from 18% for Core-1 to 10% for Core-5). Correspondingly, the enhancement in water permeability also diminished. For the tight Core-1, water permeability increased significantly from 5 mD to 23 mD. In contrast, for the more unconsolidated Core-5, the permeability increased only moderately from 40 mD to 61 mD. This phenomenon is attributed to the smaller pore-throat radius in tighter cores. Wettability reversal more effectively converts displacement resistance into a driving force in such formations. Consequently, the improvement in injected water flow efficiency is more pronounced, reflected in a greater water permeability increase in low-permeability cores.

3.8. Pilot Field Trials

Building upon promising laboratory EOR results, field trials of CQ application were conducted at two pilot wells (C-9 and C-17) in the Huabei Oilfield. A huff-and-puff injection technique was employed onsite to enhance the dispersion efficiency of the CQ solution within the formation.

As shown in Figure 12, prior to treatment, Well C-9 exhibited a stable oil production rate of 0.32 t/d with a high produced water cut of approximately 93%. Well C-17, after a period of stable production at 0.4 t/d, experienced a continuous decline, reaching only 0.18 t/d with a water cut rising to 92% immediately before treatment. Given the subeconomic production levels and significant need for production enhancement at both wells, CQ injection operations were performed from 14 November to 20 November 2024. Based on a comprehensive analysis of well logging data from pilot wells and preliminary calculations of the CQ treatment radius, combined with operational costs, the field trial employed a 2% CQ concentration. This chemical slug was alternately injected with formation water to achieve progressive dilution while expanding sweep coverage, ultimately enhancing oil recovery.

Subsequent production responses were significant. For Well C-9, the oil production rate increased from 0.32 t/d to a peak of 1.45 t/d. Although some production decline occurred post-peak, data up to early May showed stabilization at approximately 1.09 t/d—roughly three times the pre-treatment rate. The water cut concurrently decreased slightly from 93% to 85%. Well, C-17 demonstrated a more pronounced response, with oil production surging from 0.18 t/d to a peak of 2.1 t/d post-treatment. A subsequent decline, possibly associated with a minor reduction in water injection, led to stabilization at around 1.0 t/d. Crucially, the water cut decreased substantially from 92% to 68%.

These results provide compelling evidence that the CQ solution resulted in significant production enhancement under actual reservoir conditions. However, it is important to note that the success of this field trial does not imply universal applicability across all similar reservoirs. Given that CQ relies on injection water for transport into the formation, its effectiveness as an EOR method may be constrained in specific reservoir types. The method’s efficacy diminishes substantially in ultra-low permeability formations (<0.1 mD), where capillary entry pressures exceeding 5 MPa physically impede solution penetration [35]. Similarly, reservoirs with elevated clay content (>15% smectite) experience porosity reduction due to hydration-induced swelling, which exacerbates pore throat blockage during water-alternating-chemical injection. Notably, these limitations are inherent not only to chemical EOR but also to conventional waterflooding—particularly in challenging reservoirs where aqueous-phase mobility dominates injectivity constraints. To transcend such boundaries, integrating CQ modification with gas-driven processes presents a strategic pathway [36]. This hybridized approach leverages gas-phase mobility to overcome aqueous transport barriers, thereby extending the applicability of wettability-alteration strategies while amplifying ultimate recovery potential.

Furthermore, our group conducted preliminary economic evaluations comparing CQ with other EOR methods based on reservoir data from test wells. The results (

Table 8. Single-well chemical costs and injection requirements.

Chemical	Dosage (t)	Price (RMB/t)	Cost (RMB)	Injection Requirement
2% CQ (Fluorocarbon)	2–3	~60 k	120–180 k	No continuous injection required
Sulfonates	5–10	~12 k	50–120 k	Concentration maintenance required
HPAM Polymer	10–20	~25 k	150–500 k
Nano-SiO2	~1	~80 k	80 k

) indicate that while CQs initial single-well cost (120,000–180,000 RMB) is higher than sulfonates (50,000–120,000 RMB) and SiO₂ (80,000 RMB), it remains lower than HPAM (150,000–500,000 RMB). The primary economic advantage of CQ lies in its one-time injection requirement, eliminating the need for continuous dosing. This simple operational procedure only requires maintaining routine water flooding during subsequent production, avoiding the recurring costs associated with traditional chemicals like sulfonates and HPAM, which typically require annual replenishment due to 20–30% polymer degradation rates. Although further observation (at least one year) is needed to confirm sustained production performance, CQs projected incremental cost per ton of oil may prove more economical than conventional methods that incur repeated chemical injections and maintenance expenses. This field trial employed alternate injection of 2% CQ solution and formation water to enhance sweep efficiency while achieving controlled dilution of CQ, thereby balancing treatment performance with application costs, which will provide more definitive data on CQs cost-effectiveness as an EOR agent.

4. Conclusions

This study applied perfluorinated silane CQ to alter reservoir rock wettability from water/oil-wet to amphiphobic, aiming to enhance oil recovery. After verifying the stable amphiphobic properties of modified cores, mechanistic analysis of reduced surface energy, lower water/oil adhesion work, and decreased IFT confirmed CQs EOR potential. Core flooding and field tests demonstrated significant oil production increases. Key findings are

Perfluorinated silane CQ was applied to modify reservoir rock surfaces, transforming hydrophilic and oleophilic cores into amphiphobic ones to enhance oil recovery. After verifying stable amphiphobic properties, mechanistic analysis—based on reduced SFE; decreased water/oil adhesion work; and lowered IFT—confirmed CQs effectiveness for EOR. Significant oil production increases were demonstrated in core flooding and field pilot trials. Key conclusions are

• A perfluorinated silane compound, CQ, was selected as an interfacial modifier and formulated into an injection solution. CQ effectively bonded chemically to the rock surface, rendering it amphiphobic. Water and oil contact angles significantly increased to 135° and 116°, respectively. The successful coating of CQ on the rock surface was confirmed via FT-IR and EDS analysis.
• The stability of the modified core’s amphiphobic properties was rigorously evaluated through salinity resistance and aging tests. For cores treated with 0.05 wt% CQ solution, increasing the salinity from 2536 mg/L to 10,659 mg/L caused only minor reductions in contact angles (water: 135° to 129°; oil: 116° to 112°). Furthermore, cores subjected to aging in both aqueous and oleic phases under sealed conditions at 70 °C retained their amphiphobicity without reverting to hydrophilic/oleophilic states. TGA confirmed that the modified cores exhibited significant thermal decomposition only above 300 °C. Collectively, these tests demonstrate that the wettability alteration induced by CQ treatment is pronounced, stable, and long-lasting, which is attributed to the robust chemical bonding between CQ and the rock.
• Analysis revealed that the CQ modification significantly reduced the rolling angle of droplets on the core surface, further lowered the SFE, and decreased the adhesion work for both water and oil. This amphiphobic surface characteristic facilitates the migration and rolling of fluids along pore channel surfaces. Additionally, the inherent ability of the CQ solution to reduce oil-water IFT constitutes a key EOR mechanism, promoting the activation and mobilization of residual oil and thereby contributing to enhanced recovery.
• Core flooding experiments demonstrated that injecting the CQ solution followed by secondary water flooding yielded an additional 14% increase in oil recovery. Furthermore, flooding tests on cores with varying properties indicated that denser cores exhibited more pronounced improvements in both recovery factor and injectivity due to wettability alteration. This is attributed to the greater influence of wettability on the magnitude and direction of capillary forces within smaller pore throats, a finding consistent with results from spontaneous imbibition experiments.
• Pilot field trials conducted in the Huabei Oilfield yielded significant production increases. The oil production rate for well C-9 rose from 0.32 tonnes per day (t/d) to 1.09 t/d, while well C-17 increased from 0.17 t/d to 1.0 t/d. Concurrently, water cuts decreased to 85% and 68% for C-9 and C-17, respectively. The sustained production enhancement observed over a subsequent four-month period confirmed the effectiveness and applicability of the CQ solution under actual reservoir conditions. Preliminary economic assessment indicates substantial potential for further optimization of overall cost efficiency through extended production cycles, given the currently controllable CQ expenses at the present synthetic scale.