Experimental Study on Improving the Recovery Rate of Low-Pressure Tight Oil Reservoirs Using Molecular Deposition Film Technology

Abstract

The intricate geological characteristics of tight oil reservoirs, characterized by extremely low porosity and permeability as well as pronounced heterogeneity, have led to a decline in reservoir pressure, substantial gas expulsion, an accelerated decrease in oil production rates, and the inadequacy of traditional water injection methods for enhancing oil recovery. As a result, operators encounter heightened operational costs and prolonged timelines necessary to achieve optimal production levels. This situation underscores the increasing demand for advanced techniques specifically designed for tight oil reservoirs. An internal evaluation is presented, focusing on the application of molecular deposition film techniques for enhanced oil recovery from tight oil reservoirs, with the aim of elucidating the underlying mechanisms of this approach. The research addresses fluid flow resistance by employing aqueous solutions as transmission media and leverages electrostatic interactions to generate nanometer-thin films that enhance the surface properties of the reservoir while modifying the interaction dynamics between oil and rock. This facilitates the more efficient displacement of injected fluids to replace oil during pore flushing processes, thereby achieving enhanced oil recovery objectives. The experimental results indicate that an improvement in oil displacement efficiency is attained by increasing the concentration of the molecular deposition film agent, with 400 mg/L identified as the optimal concentration from an economic perspective. It is advisable to commence with a concentration of 500 mg/L before transitioning to 400 mg/L, considering the adsorption effects near the well zone and dilution phenomena within the reservoir. Molecular deposition films can effectively reduce injection pressure, enhance injection capacity, and lower initiation pressure. These improvements significantly optimize flow conditions within the reservoir and increase core permeability, resulting in a 7.82% enhancement in oil recovery. This molecular deposition film oil recovery technology presents a promising innovative approach for enhanced oil recovery, serving as a viable alternative to conventional water flooding methods.

1. Introduction

Oil and natural gas, as fossil energy sources, still play a crucial role in social and economic development. Currently, most old high-permeability oilfields have entered the stage of high water cut and high oil recovery rate, resulting in the oil reservoirs being generally flooded with water, while the remaining oil is distributed in scattered locations and requires serious effort to extract [1,2,3,4,5]. Therefore, there is an urgent need to solve new problems regarding how to improve the final output of these old sedimentary layers with high water content by changing the injection agent [6,7]. In addition, many low-permeability reservoirs have characteristics such as low porosity, low efficiency of water-driven oil extraction, small pore volume, and high injection pressure, making them very challenging to develop during the recovery process [8,9,10].

There are many methods to enhance oil and gas recovery; polymer flooding and three-component composite flooding are currently the most widely used in oilfields [11,12,13]. Polymer flooding using polyacrylamide as the main component is a common enhanced oil recovery technology that has played a role in delaying oilfield production decline. However, due to the molecular structure characteristics of polymers, they are prone to degradation in overheated and oxidative environments and are not compatible with certain salts in the reservoir [14,15]. In addition, there are many difficulties in solution preparation, reservoir injection, oil–water separation of produced fluid, and the treatment of wastewater containing polymers. The three-component composite flooding injection segment includes surfactants, polymers, and alkali (a mixture of Na₂CO₃ and NaHCO₃), of which the high pH value of the alkali solution causes clay dispersion and migration in the oil reservoir, resulting in a decrease in oil reservoir permeability [16,17]. The formation of extremely low interfacial tension between the system and crude oil makes it difficult to break the emulsion in the produced fluid. In addition, there is a problem of rod tube corrosion, greatly limiting its application range [18].

In 1890, Lord Rayleigh first proposed the concept of molecular deposition films in the Proceedings of the Royal Society of London [19]. McShane et al. (2004) studied ordered ultra-thin layers by self-assembly of molecules through electrostatic attraction between cations and anions [20]. Gao et al. (1994) [21] assembled functional polymer electrolytes and superlattice structures composed of an alternating arrangement of two positive ions, naming this type of structure a “molecular deposition film” (MD film) or nanolayer.

When researchers were exploring the frictional properties of molecular films on rock surfaces, they first proposed that molecular films might be applied in the process of oil extraction [22,23,24,25]. Shamsudin et al. (2023) [26] used diethylamine and epichlorohydrin as raw materials. Wang et al. (2023) [27] used epichlorohydrin and dimethylamine as raw materials to prepare two kinds of organic polycationic bis-quaternary ammonium salt-type molecular film agents by means of condensation polymerization, free radical polymerization, and ring-opening polymerization mechanisms at the same time. Zhang (2016) [28] reacted ethanolamine and epichlorohydrin to react in ethanol solvent to prepare bis-a halogenated intermediate and then added triethylamine for a quaternization reaction to successfully prepare a double quaternary ammonium salt-type membrane flooding agent. Researchers (2021) [29] performed nuclear magnetic resonance mapping analyses on the source rock reservoirs selected from the United States and the United Kingdom, subsequently conducting hydrothermal pyrolysis and employing an enhanced version of the Rock-Eval pyrolysis method, complemented by organic petrology analyses of both original and pyrolyzed samples under reflected white light and ultraviolet light excitation. Yang et al. (2020) [30] investigated the impact of quaternary ammonium salt-type clay stabilizers on the surface properties of clay minerals and observed that these salts could alter the hydrophilicity of clay mineral surfaces, reducing contact angles.

Molecular deposition (MD) membrane oil-injection technology is a new type of tertiary oil recovery technology that not only fills the gaps of the two previous oil-injection methods but also has unparalleled features and advantages compared to traditional chemical injection [31,32]: (1) In terms of oil recovery efficiency, water injection, polymer injection, and three-component composite injection mainly rely on displacement mechanisms, while membrane agent injection relies on imbibition mechanisms. The imbibition action of the membrane agent is more conducive to the initiation of residual oil in medium-sized and small pores. Therefore, the oil recovery efficiency of the MD membrane agent is higher than that of any previous agent. Moreover, MD membrane agent injection can further improve the oil recovery rate based on water injection, polymer injection, and three-component composite injection. (2) From the properties of the MD membrane oil-injection agent itself, the formation of the nanometer-level MD ultra-thin film is a self-assembly process that relies on the balance of static electrical interactions between the rock surface and the film-forming molecules without any external force. Moreover, the thermal stability and mechanical stability of the MD membrane are good; the MD membrane oil-injection agent has a low concentration and high oil recovery efficiency, and no alkali, surfactant, or other chemical reagents are needed, causing minimal damage to the reservoir; additionally, the MD membrane oil-injection agent has good anti-swelling effect and bactericidal ability; its surface activity is not high, and it will not cause the unfavorable influence of crude oil emulsification; the solution of the membrane agent is neutral, and it causes almost no corrosion to the injection or production system pipes or casings and does not harm the human body.

There have been experimental studies on the molecular deposition film displacement mechanism, permeability characteristics, and other aspects conducted in laboratory settings [33,34,35,36]. It has been observed that unlike conventional chemical agents, the membrane agent system has minimal impact on the interfacial tension between oil and water as well as the viscosity of crude oil. However, there is a significant adsorption amount and rate of membrane agent molecules in the rock core, indicating that the molecular deposition film displacement mechanism differs from traditional chemical displacement methods such as polymer flooding, surfactant flooding, alkali flooding, and composite flooding [12,37,38]. This method utilizes a water solution as its transmission medium, with membrane agent molecules relying on electrostatic interactions for film formation. The effective molecules of the membrane agent deposit onto negatively charged rock surfaces to form nanometer-thick ultra-thin films that alter reservoir surface properties and interaction states with crude oil by reducing adhesion between crude oil and rock surfaces.

The current reservoir pressure in the Da’anzhai formation in the study area is low, with significant degassing and an accelerating production decline rate. The recovery rate is less than 6%, and the effectiveness of water flooding technology application is poor. Based on the molecular deposition film mechanism of enhanced oil recovery, research was conducted to optimize the concentration of molecular deposition film injection and simulate cyclic oil recovery experiments. A quantitative evaluation of the impact of molecular deposition film drives on reducing driving pressure, improving permeability, and increasing oil recovery rate in low-permeability reservoirs was carried out. These studies indicate that optimizing the concentration of molecular deposition film injection and simulating cyclic oil recovery experiments are effective methods that can significantly enhance oil recovery efficiency and increase oil production from low-permeability reservoirs.

2. Geological Characteristics of Reservoirs

2.1. Reservoir Porosity and Permeability Characteristics

Porosity and permeability are critical parameters that quantify the ability of fluids to traverse porous rocks under pressure differentials. Permeability serves as a vital metric for assessing fluid flow through porous media and is governed by Darcy’s law. The permeability of a rock with respect to any given fluid is referred to as phase permeability or effective permeability [39]. Darcy’s law constitutes a fundamental principle that describes fluid movement within porous media, applicable to both single-phase and multi-phase flow scenarios. The absolute permeability of a rock, denoted as K, is determined through linear flow experiments conducted under conditions of 100% saturation; its value signifies the maximum capacity of the rock for facilitating fluid passage under specified conditions. The magnitude of K primarily depends on factors such as pore throat size, shape, and connectivity, which are intricately linked to the overall pore structure. Relative permeability quantifies a rock’s ability to permit each phase of a multiphase flow.

The porosity and permeability characteristics of reservoir rocks form essential foundations and key determinants of oil and gas production efficiency. Porosity aids in evaluating the storage capacity of reservoirs, whereas saturation assesses their hydrocarbon content. Permeability indicates both the challenges associated with oil extraction processes and their effectiveness within reservoirs. Collectively, comprehensive assessments of reservoir rock permeabilities provide crucial insights for evaluating extraction difficulties and efficiencies; these values are influenced by various factors including pore structure variations in rocks, properties inherent to involved fluids, and states pertaining to multiphase coexistence. Consequently, conducting thorough investigations into reservoir rock permeability characteristics holds significant importance for optimizing strategies related to oil and gas production.

The Da’anzhai oil reservoir in the central area of the Sichuan Basin is a large-scale fractured reservoir with localized oil enrichment, buried at depths ranging from 2000 to 3000 m. The original formation pressure ranges from 16 to 47.5 MPa, and the formation pressure coefficient ranges from 0.8 to 1.7. The geothermal gradient is approximately 2.07 °C/m, while the crude oil density falls between 0.6 and 0.8 g/cm³, with viscosity ranging from 0.2 to 4.0 mPa·s [40]. The total thickness of the reservoir spans from 40 to 110 m; it is primarily composed of biogenic fragmental limestone and mainly distributed in the Daiyi and Dasiya sections. Individual layer thickness generally varies between 3 and 20 m, with cumulative thickness reaching up to 40 m. In addition, the formation thickness in Lianggaoshan area typically ranges between 50 and 150 m. The reservoir is primarily developed in the Lianggaoshan section, characterized by light gray fine-grained (feldspar quartz) sandstone lithology. The individual layer thickness generally ranges from 1 to 4 m, with a cumulative thickness of 10 to 20 m. The reservoir exhibits poor properties, with porosity typically below 2%, permeability below 0.1 × 10⁻³ μm², and total organic carbon (TOC) content ranging from 1.2% to 1.7%. It possesses complex geological characteristics including very low porosity, extremely low permeability, and high heterogeneity. In comparison with the features of most low-permeability oil reservoirs domestically and internationally, the Da’anzhai oil reservoir in the Sichuan Basin of China falls into the category of a very low-porosity and low-permeability oil reservoir; its properties are relatively poor, posing greater challenges for development.

2.2. Mineral and Sensitivity Characteristics

2.2.1. Experimental Instruments

The X-ray diffractometer (XRD) is modeled after the Bragg experimental apparatus and integrates advancements from various fields, including mechanical and electronic engineering. This diffractometer comprises four fundamental components: an X-ray generator, a goniometer, a radiation detector, and a detection circuit. Its operational principle involves irradiating a polycrystalline sample with characteristic X-rays while capturing diffraction data through the radiation detector.

The angle measuring device of the instrument exhibits an accuracy exceeding 0.02° and a resolution greater than 60%, with overall stability maintained within ±1%. The operating voltage ranges from 30 to 45 kV, while the operating current varies between 20 and 100 mA. The scanning speed is set at 2°/min, and the scanning range can be adjusted based on the mineral species present in the sample under examination and the positions of selected diffraction peaks; it is typically configured to be between 5° and 45°.

2.2.2. Result Analysis

The results of X-ray diffraction experiments indicate that the reservoir is predominantly composed of quartz, dolomite, and calcite, with an average clay mineral content of 41% (Figure 1). It also contains minor amounts of siliceous material, terrestrial detritus, organic matter, and pyrite. The clay minerals commonly exhibit imogolite interbeds and sensitive mineral components such as pyrite, suggesting potential susceptibility to damage within the reservoir.

The results of the reservoir sensitivity test indicate that the reservoir demonstrates moderate to strong water sensitivity (Figure 2), thus necessitating the use of an entry fluid with favorable anti-swelling properties.

In almost fifty years of continuous exploration and development, the depletion-type mining method has been predominantly utilized. The outcomes of the two water injection development trials were inconclusive, resulting in a substantial reduction in oilfield pressure to 2–7 MPa, severe oil depletion, and a progressively deteriorating trial repair effect. Methods for enhancing oil recovery encompass gas injection, chemical flooding, microbial oil recovery, and electrokinetic methods [7,41,42]. While these approaches have specific advantages and disadvantages as well as application conditions (

Table 1. Main methods for improving the recovery rate of low-permeability reservoirs at present.

Main Methods	Advantage	Disadvantages and Existing Problems
Microorganisms	Low investment cost, low consumption of chemicals and energy, greater economic competitiveness than other methods, and great potential.	The mechanism is complex, and when effective bacteria are cultivated and propagated in the oil layer, the native bacteria will multiply, causing formation damage and producing harmful gases such as H2S.
Gas injection method	Mature technology; easy to achieve injection production balance; the damage to the oil well is minor; the process flow is simple and easy to manage; the economic benefits are greater than those of water injection.	Gas has a corrosive effect on the pipeline network, requiring a gas source with high input and making the pipelines prone to gas leakage.
Chemical flooding (surfactant, composite flooding)	The theory is mature and widely applied.	The cost of surfactants is high, the investment in composite flooding is high, the risk is high, and there are many problems (scaling and blockage).
Internal combustion explosion	Low cost, good economic benefits, and great potential.	There are certain safety risks that need to be addressed.

) [43,44], it is challenging to fully apply them to the actual circumstances of the Da’anzhai oilfield.

Due to its low-concentration use, minimal investment, and simple construction process, molecular deposition film driving technology can be effectively utilized in on-site trials using the existing injection well network and facilities. These trials have demonstrated significant increases in oil production. These attributes indicate that this technology has the potential to enhance the recovery rate of the Da’anzhai oilfield and is anticipated to emerge as a promising new method for improving water-drive-based recovery rates.

3. Mechanism of Molecular Deposition Film Technology

3.1. The Basic Concept and Composition of Molecular Deposition Films

The process of preparing molecular deposition film technology is straightforward, requiring no expensive instruments or equipment. The assembly process reaches an equilibrium state and is not constrained by the shape or size of the substrate. In comparison to traditional self-assembled ultra-thin films and Langmuir–Blodgett (LB) supermembranes, molecular deposition films exhibit low surface energy, good chemical inertness, thermal stability, mechanical stability, and strong adhesion to the substrate without any toxicity or pollution. Both direct experimental evidence and theoretical support suggest that depositing single-layer and double-layer MD (molecular deposition) films on porous spherical carriers enables the emergence and establishment of molecular deposition film oil displacement technology.

The technology of molecular deposition film for oil recovery primarily employs a water solution as the transmission medium, relying on strong electrostatic interactions between ions to facilitate its effectiveness. This method results in the formation of a robust single-molecule-layer ultra-thin film on the reservoir surface, which plays a critical role in reducing adhesion between the oil and the solid surface. By minimizing this adhesion, it significantly decreases both surface tension and oil–water interfacial tension, thereby promoting more efficient fluid movement. As concentration increases within the solution, it is noteworthy that there is no transition into a “micelle” state; instead, this technology maintains stability without altering the viscosity or fluidity ratio of the solution system. This characteristic ensures that flow properties remain consistent throughout various operational conditions, allowing for predictable performance during application. The process involves gradual formation of an ultra-thin film that advances toward its furthest point within the porous media. As this thin film develops and spreads across surfaces within the reservoir, it effectively strips away trapped oil molecules from their adhering sites. The action of water washing further enhances this effect by facilitating displacement; thus, oils are efficiently washed out from formations through hydraulic forces generated by flowing water.

This mechanism not only improves overall water washing efficiency but also contributes to higher oil recovery rates than traditional methods. Enhanced interaction at interfaces allows better mobilization of residual hydrocarbons that would otherwise remain entrapped in rock pores. Furthermore, understanding how molecular deposition films interact with different geological formations can lead to optimized formulations tailored for specific reservoir conditions. Such advancements could result in improved strategies for enhanced oil recovery (EOR) techniques while ensuring minimal environmental impact associated with extraction processes.

3.2. Mechanism of Molecular Deposition Film Technology

The mechanism of molecular deposition film oil recovery technology differs from those of traditional chemical recovery methods such as polymer flooding, surfactant flooding, alkali flooding, and composite flooding. This technology utilizes a water solution as the transmission medium, and the molecular deposition film agent relies on electrostatic interactions to form a thin film that effectively deposits on the negatively charged rock surface to create a nanometer-thin film, altering the interaction state between the reservoir surface and crude oil. This facilitates the removal of crude oil by injected fluids during pore washing, thereby achieving enhanced oil recovery. After over a year of research, it was found that this technology primarily contributes to altering wetting properties, enhancing spontaneous imbibition ability, increasing diffusion effects, and reducing oil–water interfacial tension in oil reservoirs.

(1)

Altering the wetting properties of the reservoir water/oil system

Under the influence of interfacial tension, stable contact angles are formed at oil–water, oil–solid, and water–solid interfaces. A contact angle less than 90° indicates hydrophilicity of the solid surface; a contact angle of 90° suggests amphipathic properties; and a contact angle greater than 90° signifies hydrophobicity (i.e., water repulsion) of the solid surface. According to the Laplace equation (where the curved liquid surface is spherical), the pressure difference between the non-wetting phase and wetting phase on both sides of the capillary tube in the reservoir represents capillary pressure.

$$p_c=2\sigma \cos \theta /r$$

(1)

where $p_c$ is the capillary pressure (MPa), $\sigma$ is the interfacial tension (MPa), $\theta$ is the contact angle (°), and $r$ is the pore radius (m).

The wetting properties of sandstone and quartz slabs were assessed using the contact angle experiment method, with kerosene (12 h soaking) and a molecular film solution (24 h soaking) as the test substances. In this experiment, the circumference (C) and height (h) of the water droplet in contact with the rock surface were initially measured to calculate the contact angle (θ). The experimental findings revealed that following treatment with kerosene, although there was an increase in the contact angle of water droplets with sandstone and quartz slabs, their wetting properties remained unchanged (

Table 2. Wetting angle test results of different rock types under different experimental conditions.

Lithology Types Tested for Wetting Angles	Clean Thin Film	Soaking with Kerosene (12 h)	Soaking with Molecular Deposition Film Solution (12 h)
Sandstone (°)	38	72	151
Quartz (°)	32	65	144

). However, after immersion in a molecular film solution, both types of slabs exhibited a transition from strong hydrophilicity to strong hydrophobicity. This suggests that adsorption of the molecular film onto the core slab surface led to its manifestation of strong hydrophobic characteristics.

Molecular deposition film oil displacement agents have the capability to mitigate the strong water-wetting clogging phenomenon. They induce a transition of strongly oil-attracting surfaces to non-wetting or weakly water-wetting states, thereby achieving optimal efficiency in oil displacement (Figure 3). Similarly, these agents can also transform strongly water-attracting surfaces into non-wetting or weakly water-wetting conditions, leading to the most effective oil-displacing outcomes.

(2)

Changing the distribution of oil and water in reservoir pores

The MD film can reduce the adhesion and dispersion of quartzite surfaces. Adhesion includes intermolecular forces, capillary forces, and electrostatic forces, indicating a highly complex adhesion mechanism. However, it can be inferred that after the ordered growth of the MD film, the microstructure modifies the surface and alters its microstructure, various force components, and their distribution on the surface, thereby reducing adhesion. Surface properties, particularly surface adhesion, play a critical role in interfacial friction. The adsorption of the MD film reduces surface adhesion, which is an important factor in reducing friction. Deposition of the MD film agent on natural subsurface quartzite exhibits favorable friction properties crucial for enhancing oil recovery.

The molecular deposition film oil displacer is instrumental in modifying the properties of solid–liquid interfaces, particularly in systems where oil and water coexist. By altering the strong oil-wetting characteristics of these surfaces, it converts them into non-wetting or weakly water-wetting states. This transformation is significant as it enhances the mobility of adsorbed oil molecules that are typically confined within a firmly adhered layer on the solid–liquid interface.

As this transition occurs, the previously thick and viscous oil film adhering to the surface begins to disintegrate. The molecular interactions involved facilitate a more efficient detachment process, allowing improved flow and movement of these trapped oils away from their original positions. Consequently, this leads to a notable conversion where an extremely thick oil film is transformed into an exceedingly thin water film.

This phenomenon not only optimizes fluid dynamics but also has implications for various industrial applications such as enhanced oil recovery processes, where maximizing hydrocarbon extraction efficiency is paramount. Furthermore, understanding how molecular deposition influences wettability can inform strategies in fields such as materials science and environmental engineering by providing insights into surface modifications aimed at optimizing liquid behavior across different substrates.

In summary, through its capacity to modify wettability characteristics at solid–liquid boundaries, the molecular deposition film oil displacer facilitates enhanced flow dynamics by enabling trapped oils to escape from tightly bound layers while simultaneously converting those layers into thinner films predominantly composed of water rather than viscous hydrocarbons.

(3)

Changing the flow properties of oil and water in reservoir pores

The molecular deposition film oil displacement agent is instrumental in enhancing the efficiency of oil recovery processes by significantly increasing the number of capillaries within reservoir rocks. This augmentation of capillary structures is critical as it reduces the flow rate of water in macropores, thereby facilitating improved interactions between the water and oil phases. Consequently, this agent enhances oil permeability, promoting the movement of oil through porous media.

During the spontaneous capillary imbibition process, particularly in low-permeability oil layers that exhibit hydrophilic properties, injected water can effectively penetrate minute capillaries due to capillary action. This phenomenon results in spontaneous imbibition—a process wherein water naturally infiltrates rock formations—thereby fostering enhanced rates of oil recovery. The capacity for water to permeate these small pores is essential for displacing trapped hydrocarbons and maximizing extraction efficiency.

In addition to its effects on fluid dynamics, during the MD film flooding process, when reservoir rocks interact with the molecular deposition film agent, a notable shift occurs in surface wettability towards hydrophilic characteristics. This alteration manifests to varying degrees depending on specific interactions between the agent and rock surfaces. Such changes are significant because they influence fluid behavior within porous media; increased wettability can lead to more effective mobilization of residual oils that would otherwise remain entrapped.

This prompts further investigation into how molecular deposition film agents not only contribute to spontaneous imbibition but also enhance overall pore utilization efficiency. A comprehensive understanding of these mechanisms would enable researchers and engineers to optimize formulations and application techniques for such agents across diverse geological settings. Ultimately, improving both yield from spontaneous imbibition and pore utilization could facilitate more sustainable practices in hydrocarbon extraction while minimizing environmental impacts associated with conventional methods. By augmenting capillary numbers and modifying wettability characteristics within reservoir rocks, molecular deposition film agents serve as critical components that enhance fluid interactions during oil recovery operations—ultimately aiming for higher yields and greater efficiencies across various applications.

(4)

Changing the viscoelastic rheological properties of reservoir fluids

Compared to traditional chemical flooding and ordinary water flooding, molecular deposition film technology offers the following advantages:

a.

It forms a single-layer nanometer-level molecular film on the rock surface with excellent thermal stability and long-term stability;

b.

The formation of nanometer-level molecular ultra-thin film during filming process does not require any external force but is completed through mutual electrostatic action between the rock surface and the film-forming molecules;

c.

The molecular deposition film water solution not only has low concentration and high efficiency but also allows relatively simple on-site operation without causing damage to the reservoir by adding other chemical agents;

d.

Molecular deposition film technology can be used after water flooding as well as for polymer flooding and composite flooding;

e.

It can be injected once, twice, or multiple times according to needs, resulting in obvious gradient injection effects;

f.

It requires low investment and involves a simple process that does not require large amounts of manpower or machinery.

(5)

Electrical transformation

The surface of oil-bearing rock typically possesses an electric charge, which plays a critical role in the interactions between fluids and solid surfaces within reservoir environments. When the pH value of the formation water falls within a specific range (6.5–7.5), it has been observed that the rock surface acquires a negative charge due to ionization processes occurring at mineral interfaces. This negative charge can significantly influence various physical and chemical phenomena, including fluid flow behavior and adsorption characteristics.

The adsorption of molecular deposit film flooding agents adds complexity to these interactions by modifying the electrical properties of both hydrophilic and hydrophobic rock surfaces. The effective components of these agents contain cationic groups that interact with negatively charged sites on the rock surface, resulting in changes in wettability and interfacial tension. Such modifications are essential for optimizing oil recovery processes as they enhance fluid mobility through porous media. When the concentration of the molecular deposit film flooding agent solution reaches 1200 mg/L, a significant transformation occurs: the previously negative surface charge transitions to a positive one, indicating zero zeta potential concentration. At this critical concentration level, any attraction or repulsion phenomena between interfaces effectively dissipate; this neutralization is vital because it minimizes resistance during fluid displacement operations. Consequently, under conditions where electrostatic forces are balanced, an enhanced recovery rate is observed during oil flooding processes. The absence of strong electrostatic interactions facilitates smoother flow dynamics and improves contact between displacing fluids and trapped hydrocarbons within pore spaces. Therefore, during oil flooding operations involving molecular deposit film flooding agents, there exists not only a mechanism for surface electrical transformation but also implications for achieving zero potential states at certain concentrations. Understanding these mechanisms provides valuable insights into how engineered additives can be strategically utilized to optimize hydrocarbon extraction while maintaining efficiency across diverse geological settings.

In summary, by manipulating surface charges through carefully controlled concentrations of molecular deposit film agents in formation waters with specific pH levels, operators can substantially improve oil recovery rates while enhancing overall operational effectiveness in challenging reservoir conditions.

4. Experiments of Molecular Deposition Film Throughput

4.1. Experimental Plan

4.1.1. Injection Concentration Optimization Experimental Plan

The injection concentration is a critical parameter for determining the economic effectiveness of molecular deposition film flooding. Variations in rock components and fluid properties within the reservoir lead to differences in the adsorption of molecular deposition film agents on the rock surface and their consumption at the oil–water interface. Research results on the mechanism of molecular deposition film flooding have revealed that different concentrations of these agents exhibit varying diffusion coefficients depending on the water quality, with specific concentration ranges capable of significantly increasing the activation energy of water molecules. Therefore, selecting an appropriate injection concentration for molecular deposition film flooding is particularly crucial.

Experiments were initially conducted using natural rock cores or model samples filled with natural crude oil shale; air permeability was assessed after vacuuming, and the samples were saturated with brine to determine water-phase permeability. Subsequently, crude oil was injected into the sample at a controlled rate to establish bound water, allowing time for even distribution throughout the core; following this, heating was applied to reach reservoir temperature before flooding with water at a specified rate until 98% or higher water content was reached. Finally, various concentrations of molecular deposition film agent solutions were injected into the sample at consistent rates until no further crude oil production was possible. Throughout these experiments, parameters such as injection pressure, produced crude oil volume, and liquid volume were recorded while calculating both water flooding effects and data necessary for enhancing oil recovery by employing molecular deposition film agents. By comparing this data set, it becomes feasible to determine an optimal injection concentration.

4.1.2. Experimental Plan for Throughput Oil Displacement Experiment

First, three reservoir core samples with similar permeability were selected. The core samples were depressurized and saturated with formation water, and the effective pore volume and porosity were calculated; bound water was prepared by displacing oil with water, and the oil saturation of the core samples was calculated; the treated core samples were then placed in a core holder and heated to the formation temperature. After a constant temperature was maintained for 12 h, overburden pressure was applied, and formation water was injected at a fixed injection rate of 0.1 mL/min until 100% water saturation was reached; oil production was recorded to assess the effectiveness of water flooding. Then, we injected 1 PV (pore volume) of optimal molecular deposition film agent at a concentration of 2000 mg/L, closed the system, and allowed it to stand for 24 h before repeating water flooding until 100% water saturation was reached. The flooding experiment was concluded, and oil production was recorded to calculate final recovery efficiency. Throughout the experiment, parameters such as injection pressure, water saturation, and recovery efficiency were graphed.

4.2. Experimental Results and Analysis

4.2.1. Limitations of Physical Simulation Experiments

In the comprehensive development of an oilfield, tertiary oil recovery represents merely one phase, with the injection method typically employing a segmented drive approach. Various injection strategies—including continuous large block injections, high-concentration small block injections, low-concentration large block injections, and stepped concentration injections—yield distinct oil displacement outcomes. In physical simulation experiments, it is important to note that molecular film displacement primarily encompasses continuous injection, high-concentration small segmented blocks, low-concentration large segmented blocks, and stepped-concentration injection. Considering the dimensions of the experimental apparatus, this study primarily employed a continuous injection method utilizing small plugs to simulate the oil displacement effect. Consequently, while the experimental environment may not fully replicate the actual molecular deposition film oil displacement process occurring in reservoirs, the results obtained can effectively reflect its underlying principles, which hold significant reference value.

4.2.2. Optimal Injection Concentration

Following water flooding, a continuous injection method was employed to introduce molecular deposition film drive agents aimed at further enhancing oil recovery rates. This approach ensures the formation of a uniform film on the rock surface by continuously and steadily injecting these agents into the reservoir. Such a film effectively reduces adhesion between oil and solid surfaces while improving fluid movement characteristics within pore spaces. To assess the impact of varying concentrations of molecular deposition film drive agents on oil displacement efficiency, experimental comparative analyses were conducted using multiple concentrations (100 mg/L, 150 mg/L, 200 mg/L, 250 mg/L, 300 mg/L, 400 mg/L, 500 mg/L, 700 mg/L, 900 mg/L, and 1000 mg/L) of molecular deposition film agent solutions. Each concentration group was rigorously controlled to ensure both reliability and repeatability in the experimental results.

The test results for oil displacement efficiency across different molecular deposition film drive agent systems are presented in Figure 4. The data indicated that oil displacement efficiency significantly increases at higher concentrations (exceeding 400 mg/L). Specifically, an increase of 13.27% in oil displacement efficiency was observed at a concentration of 400 mg/L. This increased to 14.41% at 500 mg/L, reached 15.03% at 700 mg/L, further improved to 15.68% at 900 mg/L, and finally reached 16.12% at 1000 mg/L. These findings suggest that once the concentration surpasses a certain threshold level, molecular deposition film drive agents can substantially enhance oil mobilization during water flooding processes, thereby effectively improving overall oil recovery rates.

Figure 5 and Figure 6 depict the increase in oil recovery efficiency using the membrane method and the correlation between residual oil saturation after membrane flooding and the concentration of the membrane agent. The black lines in the Figure 6 delineate the boundary between water flooding and molecular deposition film flooding. The left side of the line corresponds to the water flooding stage, while the right side indicates the molecular deposition film flooding stage.

Based on the experimental findings, it is evident that an increase in the concentration of the membrane agent corresponds to a marked improvement in membrane flooding effectiveness. This enhancement results in a significant reduction in residual oil saturation within the reservoir, which is critical for optimizing oil recovery rates. The correlation between concentration and efficiency highlights the necessity of refining chemical formulations employed in enhanced oil recovery processes.

From an economic standpoint, it becomes essential to consider input/output ratio analyses when determining optimal operational strategies. In this context, an ideal concentration for the membrane agent has been identified at 400 mg/L. This concentration effectively balances cost-efficiency with performance efficacy, ensuring judicious resource utilization while achieving substantial advancements in oil displacement. However, specific factors influencing overall efficacy during implementation must be taken into account. For instance, adsorption of the molecular deposition film agent near wellbore areas can result in localized variations regarding agent availability and effectiveness. Dilution effects from formation water should also be considered, as they may alter the effective concentrations of injected agents over time.

To address these challenges comprehensively, it has been determined that initially injecting the membrane agent at a higher concentration of 500 mg/L for a specified duration will yield sufficient initial impact before transitioning to 400 mg/L. This strategy mitigates potential losses due to adsorption and ensures that adequate concentrations remain active within critical zones throughout the injection process.

4.2.3. Results and Discussion of Throughput Experiments

During the molecular deposition film transport simulation experiment, the variations in driving pressure, permeability, and oil recovery are illustrated in Figure 7, Figure 8 and Figure 9. The water drive pressure prior to the introduction of the molecular deposition film was measured at 29.7 MPa. Following its introduction, an initial pressure of 8.3 MPa was recorded, which subsequently stabilized at a final equilibrium pressure of 27.1 MPa after sufficient time had elapsed for system adjustments to occur. This change represented an 8.2% reduction in water drive pressure compared to measurements taken before the introduction of the molecular deposition film. Furthermore, permeability exhibited notable changes during this process; it stood at 0.18 mD before introducing the molecular deposition film but increased significantly to 0.26 mD afterward, marking a substantial increase of approximately 44.4%. This enhancement in permeability is critical as it facilitates improved fluid flow within porous media, thereby enhancing overall efficiency during oil extraction processes. Under initial water drive conditions using water alone, without any chemical intervention, oil recovery reached a level of 46.8%. However, following the introduction of the molecular deposition film and continued application of water drive techniques, this figure improved markedly to reach an impressive rate of 58.6%. This significant enhancement boosted the oil recovery rate by an additional margin of approximately 10.8%, indicating that effective strategies can lead to considerable improvements in resource extraction.

Throughout this experiment, it became evident that utilizing molecular deposition films has a substantial impact on enhancing oil recovery rates primarily due to two key mechanisms: their adsorption effect during injection and their dilution effect on formation water properties over time. The adsorption mechanism allows better interaction between injected fluids and reservoir rock surfaces while reducing interfacial tension between the oil and water phases; meanwhile, dilution effects help maintain optimal concentrations within pore spaces throughout various stages of fluid movement.

During the water flooding process, water injection can induce the expansion of pore spaces within the rock, thereby increasing its permeability. Consequently, injecting 4–5 times the pore volume of water in the later stages of the experiment may further enhance the expansion of these pore spaces, resulting in an increase in measured permeability (Figure 8).

Following the analysis of molecular deposition film sweep experiments conducted on various formulations, as detailed in

Table 3. Summary of results of molecular deposition film throughput experiments.

Molecular Deposition Film Number	Pressure at Final Equilibrium (MPa)		Permeability at Final Equilibrium (mD)		Throughput Efficiency (%)		Improvement in Throughput Efficiency (%)	Starting Pressure (MPa)
	Early Water Flooding	Subsequent Water Flooding	Early Water Flooding	Subsequent Water Flooding	Early Water Flooding	Subsequent Water Flooding		Early Water Flooding	Injection of Molecular Deposition Films	Early Water Flooding
1	29.1	26.8	0.1186	0.133	47.45	54.79	7.34	12.5	9	7.8
2	3.78	2.69	1.91	2.33	43.33	45.11	1.78	3.98	2.03	2.36
3	0.061	0.024	113.55	293.91	47.45	54.54	7.09	0.018	0.017	0.012
4	0.3	0.22	0.24	0.29	40.62	43.81	3.19	0.18	0.116	0.098
5	30.5	27.2	0.0178	0.255	65.59	70.18	4.59	13	14	10

, it was observed that the permeability across all core flow conditions had been significantly enhanced. This improvement in permeability is essential for facilitating fluid movement through porous media, thereby optimizing oil extraction processes. The tested formulations not only effectively reduced subsequent water drive pressure but also contributed to a decrease in initial pressure levels. Furthermore, these formulations exhibited enhancements in sweep efficiency during the molecular deposition film sweep process, with improvements ranging from 1.82% to 7.59%. Such increases are indicative of improved displacement and mobilization of oil within the reservoir, which can lead to higher overall recovery rates.

The experimental results suggest that employing molecular deposition film flooding can further enhance oil recovery efficiency following conventional water flooding techniques. This method not only improves oil yield but also plays a significant role in reducing both water cut and injection pressure throughout operations. A lower water cut indicates more effective separation between the produced oil and water phases, which is crucial for maintaining product quality and economic viability. Additionally, by lowering the injection pressures required for fluid movement through reservoirs, operational costs may be minimized while ensuring sustained production rates over time. These findings underscore the potential benefits of integrating molecular deposition films into existing enhanced oil recovery strategies as they offer dual advantages: improving hydrocarbon extraction efficiencies while simultaneously addressing challenges associated with excessive water production.

5. Conclusions

The X-ray diffraction experimental results indicated that the primary mineral composition of the studied reservoir formation consists of quartz, dolomite, and calcite, with an average clay mineral content of 41%. Additionally, it contains minor amounts of siliceous materials, terrigenous sediments, organic matter, and pyrite. Sensitive minerals such as imogolite and pyrite are commonly present in the clay minerals. The reservoir sensitivity test demonstrated a medium to strong water sensitivity characteristic.

As the concentration of the molecular deposition film agent increases, the oil displacement efficiency of the molecular deposition film improves. The increase in concentration of the molecular deposition film agent leads to a reduction in residual oil saturation after molecular deposition film displacement. From an economic standpoint, a concentration of 400 mg/L for the membrane agent is most favorable in terms of the input/output ratio. Taking into account the adsorption of the molecular deposition film agent in the near-well zone and its dilution effect on formation water in the oil reservoir, the recommended course is to initially inject 500 mg/L of molecular deposition film agent for a period before transitioning to 400 mg/L.

The results of molecular deposition film displacement experiments demonstrate that molecular deposition films can effectively improve oil recovery rates in complex reservoirs characterized by very low porosity, very low permeability, and high heterogeneity. Furthermore, they are capable of reducing injection pressure, increasing injection capacity, and lowering initiation pressure. These enhancements lead to a significant improvement in the flow conditions within the reservoir, resulting in an increase in core permeability and ultimately leading to a 7.82% rise in oil recovery.