Introduction

One of the most common production engineering problems is the detachment of sand particles and grains from the reservoir rock structure and their transportation along with hydrocarbon fluids. When fluid passes through the porous media in unconsolidated reservoirs, sand particles detach from the reservoir rock and are transported with the fluid. Additionally, water production causes the sands to loosen, resulting in increased sand production. Research has shown that approximately 70% of the world’s oil production comes from unconsolidated and semi-consolidated reservoirs (Nouri et al. 2003). This phenomenon leads to sand production along with the production fluid, causing erosion in tubes and wellhead facilities, as well as blocking the production fluid flow (Ahad et al. 2020; Alakbari et al. 2020; Farias et al. 2007). Formation sand production results from unconsolidated or detached sand grains around the wells. These are typically rocks with low or medium resistance and little to no cementing or bonding material between the grains, or only a small amount. Sand production can occur immediately or develop during the well’s lifecycle (Allen and Roberts 1978). Sand control methods are generally categorized into two groups: mechanical and chemical. In mechanical methods, sand particles are prevented from entering the well using equipment such as screens and gravel packs (Morgan et al. 2005). One of the main challenges of mechanical sand control methods is the high cost of equipment installation and the difficulty of maintenance and replacement in case of issues (Chuah et al. 1994).

Chemical methods involve injecting materials into the formation to strengthen it around the wellbore. These materials act like glue to prevent sand grains from moving (Tabar et al. 2021). However, filling part of the pore space can result in changes in permeability. Chemical methods can be divided into two groups: (1) in situ consolidation, and (2) agglomeration of sand particles (Popov and Petrakov 2021; Gunningham et al. 1996).

Chemical consolidation includes injecting substances into the formation to increase its strength. This method enhances the compressive strength of the reservoir and the resistance of sand particles to the forces generated by fluid production (Marfo et al. 2015). Different materials used for chemical consolidation include the precipitation of calcite (CaCO3) through enzymes, organosilanes, and polymers with nanoparticles (Kotlar et al. 2005). Among these materials, polymer materials are quite useful (Alakbari et al. 2020). They are non-crystalline organic polymers used in adhesives and composite coatings in the oil industry. The advantage of using chemical materials for reservoir applications is their ability to provide effective consolidation and stabilization. However, it is essential to consider the potential disadvantages, such as possible alteration of reservoir permeability. In this regard, polymer materials offer several advantages, including increased compressive strength up to 2000 psi, high resistance to heat, good resistance to chemicals, substantial adhesive strength, low cost, and compatibility with higher temperatures up to 215 °C (Alakbari et al. 2020; Broughton 2012; May 2018). These factors make polymers a preferred choice for reservoir consolidation. There are two types of polymer materials: thermal polymer base (hardens when exposed to heat) and thermoplastic (flexible when heated) (Mishra and Ojha 2015). Thermal polymer base, when exposed to heat, undergoes irreversible changes from a soluble state to a solid state. These polymers have relatively low molecular weight and form cross-links with other molecules during the curing process. In contrast, thermoplastic polymers have reversible properties, changing their physical state under different temperature and pressure conditions. They consist of monomers with very high molecular weight (Mishra and Ojha 2015). Epoxy and furan resins are commonly used in chemical consolidation and have excellent chemical and thermal resistance, along with strong adhesive properties. In a comparison of the efficiency of furan and epoxy resins, it was found that epoxy resin provided greater compressive strength than furan resin in the core, although epoxy resin reduced permeability more than furan resin did (Tabbakhzadeh et al. 2020). Mahardhini et al. (Mahardhini et al. 2021) (2021) successfully injected epoxy resin into a well in the Mahakam field in Indonesia, and the well continued production for 11 months without sand-related issues. In 2023, Trujillo et al. injected epoxy resin into a well in the Vienna field after obtaining appropriate permeability and compressive strength results in laboratory tests, effectively stopping sand production (Trujillo et al. 2023). Chemical consolidation in reservoirs with a high percentage of clay is typically avoided due to the presence of clay particles between the polymer and sand, which can cause swelling and hinder the increase in compressive strength. However, in 2023, Recio et al. successfully used a heteroaromatic-based resin composition in sand with 25% clay and obtained suitable compressive strength (Recio et al. 2023). Further research is needed for chemical consolidation in formations with lower permeability containing high clay content.

The agglomeration method is based on reducing the electrostatic charge between sand particles. This method employs processes like charge neutralization or polymer bridging and is usually coupled with sand screens or slotted liners (Hassan et al. 2020). By injecting a suitable fluid to reduce the zeta potential on the surface of the particles, the electrostatic repulsion force between sand particles decreases. This causes the sand particles to come closer together, leading to an increase in their contact surface and a decrease in their mobility, ultimately strengthening them (Hassan et al. 2020; Popov and Petrakov 2021). It’s important to note that this method is not a permanent treatment and must be reapplied (Hassan et al. 2020). When used in sandstone formations, it maintains the wettability and hydrophilicity of the formation rock (Mendez et al. 2011). In 2018, Styward et al. introduced the sand agglomeration method as an alternative approach to strengthening sand particles in an Indonesian field. In this method, the zeta potential decreases, causing not only the sand particles to adhere to each other but also to the rock surface. The zeta potential range in this method is reported to be between − 5 mV and + 3 mV, with permeability decreasing only slightly. This method can be applied in reservoirs with very low to high permeability and temperatures up to 350 degrees Fahrenheit. It doesn’t create stickiness but generates an ionic attraction that prevents particles from moving relative to each other (Styward et al. 2018) Nanoparticles can form an integrated layer on the surface of loose sand to control sand production while maintaining optimal permeability. This layer brings sand grains closer together, increasing compressive strength to facilitate oil production. In 2016, Mishra et al. used nano silica along with urea-formaldehyde resin and achieved a 90% retention of the initial permeability, along with a significant increase in compressive strength (Mishra and Ojha 2016b).

Table 1 summarizes the research that has been done on the laboratory or field scale on resins and nanoparticles.

Table 1 Literature review
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Previous literature (Kotlar et al. 2005; Shang et al. 2019) on chemical sand consolidation has not reported a significant increase in compressive strength alongside a high level of regained permeability. Previous studies (Mishra and Ojha 2016b; Tabbakhzadeh et al. 2020) on reservoir rock wettability also lacked a complete investigation, likely due to the adhesion of chemicals used in this method and the potential alteration of reservoir rock wettability. In this article, by designing the Taguchi experiment and adding nano silica and surfactant to the epoxy resin, we increased the acceptable compressive strength and achieved very little residual permeability while significantly improving the wettability of the reservoir rock. Taguchi design methodology was employed to optimize resin, hardener, and nanoparticle proportions for both 15% and 30% clay content sands. Dr. Genichi Taguchi developed his theory in the early 1950s, and it continued to evolve throughout the 1980s. Since then, it has been adopted by companies worldwide. Taguchi believed that the most effective way to improve quality is to design it into the product itself. There are various models of the Taguchi orthogonal array, such as L9 representing eight experiments, L18 representing 18 experiments, etc (Taguchi 1995). The selection of the array should be based on the factors and levels chosen for a specific investigation, as some may be more suitable than others due to higher test requirements (Tan et al. 2017; Khalifa and Lawal 2016). The purpose of using this method is to reduce the number of tests and reach optimal concentrations more precisely and faster. Research has shown that Taguchi’s method has been able to reduce costs and increase the quality of experiments by properly designing experiments and providing accurate results (Unal and Dean 1990).

Materials and methods

Materials

In this study, the materials used for experimentation include epoxy resin, hardener, silica nanoparticle powder, solvent (used to dilute and reduce fluid viscosity), and Sodium dodecyl sulfate (SDS) surfactant. Crude oil (API 29.55) and formation water with a pH of 5.6, a density of 1.1, and a salinity of approximately 180,000 ppm were obtained from the Ahwaz oil field in the southwest of Iran. Figure 1 displays the SARA analysis of the crude oil, and Table 2 presents the analysis of the formation water.

Fig. 1
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SARA analysis of Ahvaz oilfield crude oil sample

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Table 2 Composition of Ahvaz formation water
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In this study, due to the unavailability of formation sands for static tests and cores for injection and consolidation fluid examination, the outcrops of the formation in the Ahwaz field were used in the experiments. These outcrop samples were crushed and processed into formation sand. Mineralogical analysis was conducted to identify the minerals present in the outcrop and to determine the presence and type of shale, as shown in Table 3. This analysis showed that the mineralogical composition of the outcrop is very similar to that of the Ahwaz reservoir rock.

Table 3 Mineralogical composition of the outcrop
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Laboratory devices

The devices used in this research include cylindrical rubber mold for making the core, BP210S model laboratory scale (with 0.001 gr accuracy), Digitronic-TFT oven (with 0.1◦C accuracy), magnetic stirrer, N530G Gas Permeability Tester (with 0. 1 md accuracy), desiccator, viscometer PCE-RVI 2 (with 2% error), FDS 350 device for fluid injection, reactor to place the core under high temperature and high pressure conditions, Ultrasonic Homogenization 3200 to disperse nanocomposite fluids in solution and UTR-0450.PVPR Uniaxial Test Machine (with 0. 1 psi accuracy) for measuring compressive pressure.

Laboratory method

This study was conducted in two separate parts on sand with 15% and 30% clay content. In the first stage, the minimum values of the materials were determined, and the compatibility of the materials was assessed. Subsequently, experiments were carried out with varying material percentages, guided by the values obtained and using Taguchi’s design. Cores were fabricated during this phase. The cores’ permeability, compressive strength, and wettability were assessed to identify the optimal fluid composition for sand with clay content of 15% and 30%. Post-consolidation, Minitab software facilitated comprehensive analysis of results, which included permeability, compressive strength, and wettability of the core samples, leading to the identification of optimal concentrations for both sands. Subsequently, the optimized fluid was injected into core samples in both simple and foam states to comprehensively evaluate its performance across sands with varying clay content. Further characterization involved mineralogical and thermal analyses, as well as Field Emission Scanning Electron Microscopy (FESEM) and Thermogravimetric-Differential Thermal Analysis (TGA/DTA), to comprehensively assess the chemical substance’s effect on sand control. Figure 2 shows the chart of the steps of conducting experiments. All experiments were performed at least twice to ensure repeatability and accuracy of the results.

Fig. 2
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Experimental procedure

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Determining the amount of resin, hardener, and nanoparticles in the consolidation fluid

At the beginning, solutions with varying concentrations were prepared by mixing solvent, epoxy resin, hardener, and nanoparticles in different amounts. These solutions were placed at a temperature of 90 degrees Celsius for 24 h to determine the quality of curing, and the solutions that cured properly moved on to the next stage.

Compatibility tests

Sometimes, when the injected fluid comes in contact with formation fluids, it reacts, and sediment is formed due to incompatibility. This event prevents the function of the consolidation fluid and damages the formation without any consolidation. Due to the 24-hour curing of the consolidation fluid in the formation, the consistency test was performed after 48 h at reservoir temperature. To check the compatibility and stability of the chemical fluid with the formation fluids before conducting the chemical consolidation test, the chemical fluid was put in contact with the formation fluid (formation water and oil), and its stability was evaluated.

Viscosity measurement

In this study, the viscosity of the consolidation fluid was measured using viscometer PCE-RVI 2. Measurements were taken at a shear rate of 0 to 250 s− 1 (0 to 200 rpm), and graphs related to the viscosity of the consolidation fluid at different shear rates were created. The viscometer has a measuring range of 15 to 100,000 cP. With an accuracy of < ± 2% of the range, the viscometer is a precise measuring device to determine the viscosity of a sample liquid. The viscosity is determined by the viscometer on the basis of an applied mechanical resistance that acts in the opposite direction to the rotational movement of a spindle.

Construction cores in the static stage

After determining the minimum concentrations of resin, hardener, and nanoparticles, solutions with varying percentages of resin, hardener, and Nano silica was prepared using Taguchi’s design. Different solutions with a weight ratio ranging from 20 to 80% were mixed with two types of sand that had aged in formation water and oil for 7 days. These mixtures were then poured into cylindrical rubber molds, compacted, and covered with aluminum. The choice of a 20% combination of fluid with sand was due to the approximately 20% porosity present in the cores taken from the outcrop, allowing the fluid to only fill that porous space. The cores were then left in an oven to cure for 24 h at a temperature of 90 °C.In this study, Taguchi method was used for designing static tests.

Contact angle, permeability, and compressive strength measurement

Various operations involving the use of different chemicals to achieve specific goals can result in chemical reactions and ion exchange between rock and fluid, leading to changes in the wettability of the formation rock. Since wettability changes are typically permanent, it is crucial to thoroughly investigate and test the impact of the fluid used in the operation on the wettability of the rock formation’s surface. Wettability changes in sands occur because of their contact with the consolidation fluid. Because permeability decreases during chemical consolidation, relative permeability becomes important to compensate the effect of reduced permeability. Therefore, wettability after chemical consolidation is important. To assess wettability after chemical consolidation, a 0.5 cm thin section was prepared from cores. The thin section was placed horizontally in formation water, and a drop of oil was carefully placed underneath it. A photograph was taken of the contact surface between the oil drop and the thin section, and the contact angle was subsequently measured using Digimizer software version 6.3.0. Figure 3 shows the laboratory schematic of contact angle measurement.

Fig. 3
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Laboratory schematic of contact angle measurement

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Consolidation fluid injection can cause a change in the permeability of the formation rock. Since changes in permeability can greatly affect the production rate, it is very important to investigate and test the effect of the fluid used in the operation on the change in permeability of the formation rock. The post-treatment permeability of the cores after curing the chemical fluid was measured by a gas permeability meter. The cores were placed in the gas permeability meter and the pressure difference between the two ends of the core was measured at four gas flow rates. Finally, permeability was measured with the help of Darcy’s law and the gradient of the line between these four points in the flow rate-pressure difference diagram,

One of the important aspects related to the consolidation of sandstone reservoirs with resin injection is the strengthening of the formation. Before performing field tests, tests to measure the amount of resistance created by the consolidation fluid should be considered, along with all the tests and considerations. The compressive strength of cores was measured using a Uniaxial Test Machine. This device applies force to the core until it breaks. Based on the cross-sectional area of the core and the force that causes the core to break, the compressive strength of the core was calculated.

Determining the optimal concentration of resin, hardener, and nanoparticle

To achieve the optimal combination of the desired fluid, Minitab software was employed. Initially, the goals for each response parameter, as indicated in Table 4, were defined. Minitab calculates individual desirability for each response, weighting them according to their assigned importance. These values are then combined to determine the composite, or overall, desirability of the multi-response system. The optimal solution is found where this composite desirability reaches its maximum. To identify the optimal points, the software utilizes numerical optimization algorithms such as the Newton-Raphson method, the Steepest Descent method, and other iterative search techniques. These algorithms work by repeatedly calculating and refining the values of the objective function until the optimal point is reached. Using an optimization plot, the settings of the variables can be adjusted, and their effects on the responses can be evaluated, ensuring that the desired optimal combination is achieved. The weight determines the shape of the desirability function, affecting how the desirability is distributed between the bounds and the target. A weight of 1 is neutral, equally emphasizing the target and bounds. Weights greater than 1 emphasize the target more, requiring closer proximity to achieve high desirability, while weights less than 1 de-emphasize the target, allowing greater deviation from it. In the optimization conducted, considering that the parameter “contact angle” is less critical compared to the other two parameters, a weight of 0.5 was applied. This choice is reflected in Fig. 4, which illustrates the differences in desirability function shapes for various weights. With a weight of 0.5, the desirability function places less emphasis on the target value for the “contact angle” parameter, allowing for more flexibility in its optimization compared to the other parameters.

Table 4 Optimization parameters detail
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Fig. 4
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Desirability function for different goals – how weights affect their shapes

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Consolidation fluid injection

Once the optimal fluid composition for sand with 15% clay was determined, the consolidation fluid was injected into the outcrop cores in both a simple and foam state (containing SDS surfactant). The injection in the core containing 15% clay was chosen because most of the analyzes of the Ahvaz formation indicated the presence of 15% clay in the Ahvaz reservoir rock. For preparing foam state, SDS surfactant was added to the surfactant solution and thoroughly mixed with a high-speed mixer. Resin foaming was utilized to enhance the final permeability regained. Prior to fluid injection, the cores were saturated with formation water for one day using a desiccator to create a vacuum and allow the water from the formation to fill the core’s empty spaces. Subsequently, the cores were saturated with oil using the desiccator for 7 days and then placed in the core holder of the FDS350 device. The core was placed in the sleeve and a pressure of 1000 psi was applied with the help of hydraulic pressure. A pre-injection of 1 PV of diesel fuel was followed by the injection of 1 PV of consolidation fluid into the cores at a rate of 5 cc/min. The cores were then removed from the core holder and cured in a reactor at reservoir temperature and pressure for 24 h. Following fluid injection into the cores, measurements of permeability, compressive strength, and contact angle were taken using the methods outlined in previous sections. Also, FESEM analysis was conducted on the cores to assess the quality of the injection.

Field emission scanning electron microscopy (FESEM)

FESEM analysis, which stands for Field Emission Scanning Electron Microscope, is a valuable tool for examining surface texture, grain size, and clay mineral distribution on sample surfaces. By using electrons instead of light, FESEM analysis provides detailed visualization of topographical features on surfaces or objects. The release and scanning of electrons from a field emission source allow for the generation of high-resolution images that can be viewed on a monitor or stored digitally for further processing. The surfaces of the sandstone reservoir are covered by the consolidation fluid when it enters the pore space of the core. When more surface area of the particles is covered by the consolidation fluid, better connection between the sand particles occurs, making chemical consolidation more effective. For this reason, FESEM analysis was used to investigate the quality of covering the surfaces of sand particles with the consolidation fluid.

Thermogravimetric - differential thermal analysis (TGA/DTA)

Additionally, a TGA/DTA test was conducted to determine the optimal consolidation fluid. TGA-DTA thermal analysis, which measures changes in a sample due to heat, provides valuable insights into the thermal stability, moisture content, and other characteristics of a chemical substance. This method aids in determining properties, such as melting temperature, molecular weight, and thermal degradation.

Results and discussion

Determining the concentration of resin and hardener

The results of the experiments to determine the optimal resin concentration showed that the ideal concentration for forming polymer chains and achieving acceptable compressive strength falls within the range of 30–50%; resin concentrations lower than 30% did not achieve the desired compressive strength, and concentrations exceeding 50% resulted in negligible permeability. Resin less than 30% cannot create many polymer networks between sand particles for rock strength, and for this reason resin less than 30% is not suitable. Also, resin above 50% will reduce the permeability of the rock due to the formation of excessive polymer networks between the sand particles.

The findings from the tests to determine the optimal hardener amount revealed that curing does not occur with less than 10% of hardener. Additionally, when the hardener concentration surpasses 30%, curing happens rapidly due to the swift formation of polymer chains. Once the hardener is mixed with the resin, curing initiates, making it impossible to inject the material. Therefore, the optimal hardener concentration was selected to be between 10% and 30%. Hardener less than 10% cannot form polymer networks. Such a hardener above 30% increases the rate of formation of polymer networks and causes a sharp decrease in the permeability of the formation.

Furthermore, 1% by weight of Nano silica was dispersed in the fluid. Achieving dispersion percentages higher than 1% in the fluid was not possible, as settling occurred after half an hour. Consequently, the Nano silica percentage was chosen to be within the range of 0–1%.

Compatibility test

The compatibility test of the formation fluid with the consolidation fluids was performed. The results showed no sediment after 48 h, indicating that the consolidation fluids were compatible with the reservoir fluid. This test was conducted after determining the optimal consolidation fluid, which showed appropriate compatibility. If the injected fluid comes into contact with the formation fluids and reacts and forms sediment due to incompatibility, the consolidation fluid cannot perform its function.

Viscosity measurement

The viscosity of the consolidation fluid should be measured to determine if it can be easily injected. High viscosity can make injection process difficult and hinder the process, as well as prevent the consolidation fluid from entering an unconsolidated formation. The viscosity of the consolidation fluid should not exceed 0.02 Pa.s to ensure easy injection (Talaghat et al. 2009). This test was performed only to ensure that there is an ability to pump consolidation fluid. Figure 5 shows the viscosities was measured at various shear rate (0 to 250 s− 1). This figure shows that the consolidation fluid undergo shear thinning behavior that there is no problem for pumping this fluid. Also, this figure shows that at ambient temperature and at shear rate of 250 s− 1, the viscosity is below 40 cp. We also know that with increasing temperature, viscosity should decrease. Therefore, the viscosity of the consolidation fluid at the reservoir temperature will definitely be below 40 cp. and there is no problem for pumping this fluid into well.

Fig. 5
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Viscosity of consolidation fluid at different temperatures

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Experiment design

Considering three levels for each of the three parameters (Nano silica, resin, and hardeners), a total of 27 different states can be obtained. Conducting tests for all these combinations, despite the lengthening of the overall testing process, can result in significant costs. Therefore, it is essential to employ appropriate and reliable test design methods to reduce the number of tests. Following the Taguchi method, the 27 broad conditions have been condensed into an L9 orthogonal array, resulting in only 9 tests. Table 5 provides more details on this test design, which is based on Minitab software. By using this method, the number of tests will be minimized, and the results of these 9 tests will be equivalent to those of the original 27 tests.The concentration percentages of each resin, hardener, and Nano silica were chosen based on the initial tests. These solutions were mixed with sand from the outcrop and cured at 90 °C for 24 h.

Table 5 Test procedure
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After chemical consolidation, three important characteristics were investigated in the manufactured cores: compressive strength, permeability, and wettability. The consolidation fluid is expected to increase the core sample’s strength while minimizing the reduction in permeability. The compressive strength should be sufficient to withstand the forces exerted by the fluid flow in the reservoir, preventing sand particles from separating from the reservoir rock and being produced. However, the reduction in permeability should be kept to a minimum to ensure that it doesn’t hinder the movement and production of oil. Furthermore, the wettability of the formation rock should lean towards being water-wet. Figure 6 depicts the cores with the molds in which they were placed.

Fig. 6
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Cores made in rubber before curing

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Permeability, compressive strength, and contact angle measurement

Table 6 displays the compressive strength, permeability, and contact angle of cores made with two types of sand. Except for samples No. 1, 4, and 7, the rest of the cores were safely removed. Unfortunately, these three samples failed due to insufficient strength, and only fragments of them remained. This indicates that the 10% hardener concentration was inadequate for achieving the minimum consolidation required. To confirm the ineffectiveness of the hardener, 10% of the experiments were repeated, yielding the same result. Figure 7 provides a visual representation of the cores removed from the rubber molds.

Table 6 Characteristics of cores made with sand containing 15% and 30% clay
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Fig. 7
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Cores removed from the tire

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As previously noted, Figs. 8, 9 and 10 depict comparative charts of compressive strength, permeability, and contact angle for the cores produced with the two types of sand. In the sand with 15% clay content, Test number 5 demonstrated the highest permeability at 363.5 md, while Test number 6 exhibited the highest compressive strength at 404.7 psi and the best contact angle at 37 degrees. These results suggest that the addition of Nano silica to the resin can enhance permeability and make the rock more water-wet. There are many benefits to silica nanoparticles compared to other potential options. Some of those benefits are ease and control of production, and the properties and interactions of silica-based materials are extremely well known. Also, silica particles are easily functionalized with different groups to make them more hydrophobic or hydrophilic (Kong and Ohadi 2010).

Fig. 8
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Permeability of the made cores

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Fig. 9
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Compressive strength of made cores

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Fig. 10
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Contact angle of made cores

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In the sand with 30% clay content, Test number 3 achieved the highest permeability at 494 md, the highest compressive strength at 282.58 psi, and the best contact angle as 39.7 degrees. It is worth noting that in the sand with 30% clay content, the compressive strength did not increase with the addition of more hardener. The high percentage of shale reduces the contact surface of the fluid with the surface of the reservoir rock, and as a result, a strong bond does not occur, because of this, compressive strength is even lower. Regarding compressive strength, except for Test 5, a decreasing trend can be observed in the results. Additionally, in formations with high clay content (30%), an increase in hardener concentration does not appear to be the reason for an increase in compressive strength.

High compressive strength and permeability are consistently essential outcomes in the sand consolidation process (Mishra and Ojha 2016a). This process involves injecting a material into the formation and introducing a consolidation fluid between the loose sand particles. The curing process signifies the transformation of the consolidation fluid from a liquid to a solid state, forming polymer chains that bond the consolidation fluid to the sand particles (Young 1965).

As observed, the compressive strength of the sand increases with higher resin concentrations, resulting in the formation of larger polymer chains. Additionally, in sand with 15% clay content, increasing the hardener enhanced the curing process, leading to a greater number of polymer chains and improved compressive strength. However, in sand containing 30% clay content, this effect is not observed due to the higher clay content, which hinders the efficiency of the hardener, thereby limiting the increase in compressive strength.

The obtained results showed that the larger amount of clay in the formation rock also causes a lower compressive strength, so that the compressive strength of the sample with 30% clay content was lower than the sample with 15% clay content, which could be due to the large amount of clay particles in the formation rock. It causes the nanocomposite fluid to not be in good contact with the surface of the formation rock due to the covering of its surfaces by clay particles, and this causes the weak bonding of the sand grains with each other and, as a result, lower compressive strength.

Increasing the resin concentration and thickening, the resin layer on the sand particles’ surface, along with the formation of larger polymer chains, narrows or even closes the pore throats through which fluids pass. Furthermore, the increased hardener content accelerates polymer chain formation, leading to a greater reduction in permeability.

After determining the optimal amounts of nanocomposite fluid constituents, the results show that as the amount of clay content increases, the required percentage of hardener also decreases, so that the optimal amounts for the sample with the 15% of clay content are 50% resin, and 30% hardener, While the optimal amounts for the sample with the 30% of clay content are 30% resin and 30% hardener.

In this study, Nano silica was added to the chemical substance due to the significant decrease in permeability in the previous step using epoxy polymer. Increasing the Nano silica content in the chemical significantly boosted compressive strength, with only a negligible impact on permeability. Nano silica is situated between the rock surface and the polymer chains, resulting in a stronger bond between the rock surface and the polymer material, improved consolidation, and increased compressive strength (Alakbari et al. 2020).

It is also evident that the consolidation fluid has effectively made the formation sand more water-wet. This can be attributed to the impact of Nano silica in the consolidation fluid, as the addition of nanoparticles intensifies the wetting effect. In essence, it makes hydrophilic surfaces even more hydrophilic and vice versa.

Optimum concentration of resin, hardener, and nanoparticles in the chemical solution by response surface methodology

To achieve the simultaneous improvement in compressive strength, reduced permeability, and altered wettability of sand formations, an optimal concentration of a chemical substance must be determined to optimize these crucial factors in sand consolidation. Using Minitab software and the response surface methodology, an optimal configuration has been established, which helped identify the ideal percentage for epoxy resin, hardener, and Nano silica. Figure 11 demonstrates that as the concentration of resin (solid content) increased, permeability decreased while compressive strength increased. This is due to the formation of larger polymer chains. It is important to note the permeability trend, which initially increases and then decreases with the addition of hardener, highlighting the necessity for optimization.

Fig. 11
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Response surface optimization diagram for sand with 15% clay content

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In contrast to the response optimization diagram for sand with 15% clay content, for sand with 30% clay content, the upper limit of resin, hardener, and Nano silica concentration does not yield optimal combined desirability. Figure 12 shows that, in this case, the lower limit is chosen for the concentration of hardener. The results of the optimal conditions can be found in Tables 7 and 8 for sand with 15% and 30% clay content, respectively.

Fig. 12
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Response surface optimization diagram for sand with 30% clay content

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Table 7 Optimum fluid for sand with 15% clay content and the characteristics of the made core
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Table 8 Optimum fluid for sand with 30% clay content and the characteristics of the made core
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After optimization, the experiments were conducted with the optimal percentages of resin, hardener, and Nano silica for two clay contents. The results for 15% clay content were: compressive strength was 398 psi, permeability was 335 md, and the contact angle was 39 degrees. Similarly, for 30% clay content, the results were: compressive strength was 271 psi, permeability was 523 md, and the contact angle was 40 degrees.

Injection of optimal consolidation fluid in cores

Based on the results of previous studies, the goal was to increase residual permeability after chemical injection. A nanocomposite fluid combined with a surfactant, chosen for its ability to occupy pore spaces, is used in the selected method. The presence of SDS surfactants in the polymer fluid, added to the process, will reduce its viscosity and allow for a more even distribution into a layer of porous material. This enables uniform curing in the medium, preventing clogging of pore spaces and throat openings. Additionally, the surfactant’s ability to reduce surface tension has lowered capillary pressure and allowed movement of oil trapped inside the core. Traditional methods have struggled to remove oil droplets, making polymer nanocomposite fluids with surfactants a viable alternative. The effectiveness of SDS surfactant in forming microbubbles in Aphron liquid has been demonstrated in previous studies conducted by Khamehchi et al. (Khamehchi et al. 2016; Alizadeh and Khamehchi 2019). In addition, the surfactant can create higher permeability after consolidation despite the presence of bubbles. Analysis has shown that the optimal weight% is 1%. In other experiments, a 1% weight concentration of SDS surfactant was added to the surfactant solution and thoroughly mixed with a high-speed mixer. Particularly, the results of surfactant-assisted injection, compared to simple injections, have proven to be more effective in reducing permeability in previous studies.(Shang et al. 2019; Nguyen and Rickman 2012).

After determining the optimal fluid, including epoxy resin and Nano silica, the consolidation fluid was injected into four cores in two simple and foam states (including 1% SDS surfactant) using the FDS350 formation damage device. These experiments were conducted to examine the impact of polymer nanocomposite fluid injection on core permeability, compressive strength, and wettability. The results can be seen in Table 9. Two injection tests were performed for reproducibility. It is important to note that the initial compressive strength was obtained from the average compressive strength of three outcrop cores.

Table 9 Optimal fluid injection
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The initial compressive strength of the outcrop was measured as 1156.35 psi. The compressive strength after injection was measured as 1230.21 psi in the simple state and 1888.85 psi after injection using surfactant. This shows that injecting epoxy resin using surfactant in a foam state was able to increase the compressive strength of the core by more than 700 psi. Comparing the compressive strength in the two cases reveals that the surfactant significantly increased the compressive strength by effectively dispersing the nanocomposite fluid in the core.

The measurement of permeability values before and after injection shows that simple injection reduced permeability by more than 38%, while this reduction was about 11% with the injection aided by surfactant, which created a foam state. This indicates that injection with the help of surfactant significantly reduced the decrease in permeability due to the foamy state and the creation of bubbles in the porous space.

After consolidating the cores, thin sections were extracted to evaluate wettability. The measurements showed that injecting nanocomposite fluid, in both simple and foam states, significantly increased the contact angle of the oil drop, indicating an increase in water wettability. It should be noted that the nanocomposite fluid may be absorbed onto the surface of the reservoir rock, leading to changes in wettability in the treated area. When a chemical consolidation agent is used, it can potentially alter the sandstone’s wettability to an oil-wet state, which can be problematic in an oil reservoir. Therefore, it is crucial to evaluate the effect of consolidation agents not only in terms of permeability reduction but also in terms of wettability changes. Figures 13 and 14 depict the contact angle in both the simple and foam states.

Fig. 13
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Simple state contact angle

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Fig. 14
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Foam state contact angle

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The wettability test shows that not only did the wettability of the rock not decrease compared to the formation water, but it also increased, and the water contact angle was reduced from 67.5 degrees to 34.24 degrees, which itself increases the relative permeability of the hydrocarbon fluid in the treated area and reduces the damage effect of the nanocomposite fluid. According to the obtained results, the optimal consolidation fluid in a foam state was able to achieve favorable results in core injection and can prevent sand production. As known, the optimal consolidation fluid in a foam state was able to increase the core’s compressive strength by more than 700 psi, while permeability recovery was about 89%, and the contact angle was reduced.

Field emission scanning electron microscopy (FESEM)

The results of the FESEM analysis of the core sample consolidated with the optimal nanocomposite fluid show that the surface of the sand particles is completely covered by the nanocomposite agent, and the sand particles are fully bonded together. Figure 15 displays the images from the FESEM analysis before and after consolidation. The figure illustrates that the foam state has effectively spread on the surface of the sands, confirming the bonding of the grains to each other and thereby enhancing their strength.

Fig. 15
figure 15

FESEM analysis related to core sample (a). Before consolidated with polymer nanocomposite fluid (b). After consolidated with polymer nanocomposite fluid

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Thermogravimetric - differential thermal analysis (TGA/DTA)

Figures 16 and 17 show the TGA\DTA diagram of the optimal fluid in a simple and foam state.

Fig. 16
figure 16

Thermal analysis of optimal consolidation fluid in simple state

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Fig. 17
figure 17

Thermal analysis of optimal consolidation fluid in foam state

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The onset of thermal degradation evident in the figures may be attributed to the initiation of polymer chain degradation. The radicals formed during this process can result in the formation of a ring structure within the polymer chain, as observed in the Differential Thermal Analysis (DTA).

In Fig. 16, it is evident that the optimal nanocomposite fluid in the simple state undergoes thermal degradation at a temperature of 355 °C. Conversely, in Fig. 17, it is apparent that the optimal fluid in the foam state undergoes thermal degradation at a higher temperature of 370 °C. This highlights the difference between the fluids in their foam state, showing that the fluid in the foam state exhibits greater thermal stability compared to the simple state.

To compare the effectiveness of the current study with previous studies, Table 10 displays the results of previous research. As known, the nanocomposite fluid investigated in this study was able to achieve high-regained permeability and create a high compressive strength. Additionally, this nanocomposite fluid has been able to hydrophilize the wettability of the rock surface compared to research conducted in other studies.

Table 10 Comparison with previous research
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Conclusions

In this study, a novel polymer nanocomposite fluid was synthesized, which has been found to offer excellent compressive strength and regained permeability after consolidation in sandstone reservoir with high clay content. Simultaneously, it effectively renders the rock surface hydrophilic. Based on this research, the following results were obtained regarding the performance of the polymer nanocomposite fluid in the process of sand production control:

  • The larger amount of clay in the formation rock causes a lower compressive strength, so that the compressive strength of the sample with 30% clay content was lower than the sample with 15% clay content.

  • The findings indicate a decrease in the required amount of resin for chemical consolidation as the clay content in the reservoir rock increases.

  • The data demonstrate significantly higher regained permeability in the foam state fluid compared to the simple state fluid, with the foam state fluid significantly enhancing compressive strength.

  • The images of cores clearly demonstrate the ability of the injected nanocomposite fluid in foam state to coat the surfaces of sand grains.

  • The results show that the nanocomposite fluid has a good ability to change the wettability of the reservoir rock towards hydrophilicity.

  • Based on this study, the synthesis nanocomposite fluid in the foam state has more thermal stability than simple state.