Increasing the compressive strength of a high clay content sandstone reservoir by chemical sand consolidation with minimal permeability reduction

Abstract

The integrity of geological formations is critically affected when external forces surpass the rock’s inherent resistance, particularly during oil and gas extraction. Insufficient formation strength to counteract declining flow pressure can result in the migration of sand particles towards the wellbore. The selection of sand control techniques is influenced by a multitude of factors, including well and reservoir conditions, operational methodologies, resource availability, and economic viability. A prevalent chemical strategy for mitigating sand migration in oil reservoirs involves the in-situ consolidation of sand using resin. This technique effectively bonds sand particles within the reservoir through an auxiliary substance, thereby minimizing sand production. In this study, we explore the efficacy of various resins—furan, epoxy, melamine formaldehyde, urea formaldehyde, and vinyl ester—on the chemical consolidation of sandstone reservoirs with high clay content for the first time. The presence of clay poses significant challenges to achieving effective polymer bonding due to its interference with both sand particle cohesion and consolidation fluid penetration. Furthermore, clay expansion can hinder enhancements in compressive strength. Our tests under static and dynamic conditions demonstrated that furan and epoxy resins yielded promising results: furan resin achieved a residual permeability of 79% with a compressive strength of 1668 psi; epoxy resin exhibited a residual permeability of 62% with a compressive strength of 1579 psi. To comprehensively evaluate resin performance, additional assessments were conducted, including wettability tests, FESEM analysis, viscosity measurements, and CT imaging. These findings provide valuable insights into optimizing chemical consolidation strategies in clay-rich sandstone reservoirs.

Introduction

Sand production stands as one of the most persistent, technically complex, and economically burdensome challenges in the global petroleum industry. This phenomenon, defined as the unwanted influx of solid reservoir matrix particles into a wellbore alongside produced fluids, represents a critical failure mode in geomechanical integrity that compromises the entire value chain from subsurface to surface facilities¹⁷. The genesis of this problem is fundamentally rooted in the interplay between the in-situ stress regime of the reservoir rock and the hydrodynamic forces exerted by fluid flow during production. When the effective stress on the formation—a function of overburden pressure, pore pressure, and the rock’s inherent tensile or cohesive strength—is exceeded by the drag and pressure gradient forces associated with production, the bonds between individual sand grains fail, initiating their mobilization²⁰. This process is often triggered or accelerated by operational factors such as increased drawdown, water breakthrough which reduces capillary cohesion and introduces two-phase flow effects, and the gradual depletion of reservoir pressure which alters the effective stress landscape²⁶. The consequences are severe and multifaceted: erosional wear on downhole completion equipment, submersible pumps, and surface chokes,wellbore instability or collapse; sand fill in the wellbore requiring frequent and expensive cleanout operations; separator and pipeline blockages; and ultimately, production deferral or permanent loss of well integrity, often forcing premature well abandonment³¹. The economic impact is staggering, with industry estimates suggesting that sand-related problems can consume 5–15% of total well operating costs, not accounting for lost production potential.

The scale of the challenge is magnified by the geological reality that a significant proportion of the world’s hydrocarbon reserves reside in geologically young, poorly lithified, or unconsolidated sandstone formations. It is estimated that approximately 70% of the world’s oil and gas production originates from reservoirs classified as unconsolidated or weakly consolidated, where the natural cementation between sand grains is minimal²⁰. In such formations, the compressive strength is frequently below 6.9 MPa (1000 psi), rendering them inherently vulnerable to mechanical failure under production stresses³¹. The sand production process is typically conceptualized in two sequential stages: first, the mechanical failure or detachment of sand grains from the bulk rock matrix due to compressive, tensile, or shear failure around the wellbore; and second, the hydraulic transport of these loose particles by the flowing fluid into the well¹⁷. This mechanistic understanding underscores that any effective sand management strategy must address either the strength of the formation, the forces acting to dislodge and transport particles, or both.

Confronted with this pervasive issue, the industry has developed a broad arsenal of sand control techniques, which are generally categorized into four principal methodologies: mechanical, chemical, production management, and well maintenance and repair¹⁴. Mechanical methods, such as standalone screens, slotted liners, and gravel packs, function primarily as filtration barriers, physically restraining sand particles while permitting fluid flow. These are often the first line of defense and are widely deployed. However, they possess inherent limitations: they can be compromised by erosion, plugging, or corrosion; their installation is complex and costly, especially in highly deviated or multilateral wells; and they do nothing to strengthen the formation itself, potentially allowing continued failure behind the screen which can lead to voids and subsequent collapse⁷. Production management, involving the careful restriction of flow rates to maintain bottomhole pressure above a "sand production threshold," is a conservative approach that forfeits maximum potential production to avoid sand influx. Chemical sand consolidation, the focus of this study, offers a fundamentally different philosophy. Instead of filtering out sand or reducing forces, it aims to engineer an increase in the intrinsic mechanical strength of the formation rock in the critical near-wellbore region. This is achieved by injecting a liquid chemical agent that permeates the pore space, coats the sand grains, and subsequently cures or solidifies in situ, creating artificial cementation that bonds the grains together¹⁵. This method can be applied as a standalone completion technique, a remedial treatment for failing mechanical controls, or a pre-emptive strengthening measure.

The chemical approach itself bifurcates into two main sub-categories: sand consolidation and sand agglomeration^9,23. Consolidation seeks to create a rigid, permeable matrix where grains are bonded at their points of contact, ideally leaving the majority of the pore network open for flow. Agglomeration, in contrast, aims to create larger clusters of sand particles that are too massive to be transported. Within the consolidation domain, the most prevalent and successful chemicals have been thermosetting polymer resins. These resins, which irreversibly transform from a liquid to an infusible, insoluble solid network upon curing, offer excellent mechanical properties and chemical resistance⁵. Key resin families include epoxy resins (known for exceptional adhesive strength and chemical resistance), furan resins (noted for good thermal stability and corrosion resistance), and amino resins like urea–formaldehyde and melamine–formaldehyde¹. The ideal resin system must satisfy a demanding set of criteria: it must have sufficiently low viscosity and suitable wettability to invade the formation pore network uniformly,it must be chemically compatible with formation fluids and minerals; it must cure reliably and predictably under reservoir temperature and pressure conditions; and critically, it must achieve a high degree of compressive strength without causing an unacceptable reduction in the formation’s permeability to hydrocarbons¹⁵. This last requirement represents the central, perennial strength-permeability trade-off that challenges all chemical consolidation designs. A resin that forms a very dense, robust polymer network will provide strong consolidation but is likely to plug pore throats, impairing productivity. Conversely, a resin that leaves pores open may fail to provide the necessary mechanical strength to withstand production stresses.

The challenge of optimizing this trade-off becomes exponentially more difficult in the presence of clay minerals, a common constituent of many sandstone reservoirs. Clay-rich formations pose a multifaceted and formidable obstacle to chemical consolidation, a problem that has received insufficient systematic study. Clays, such as smectite (montmorillonite), illite, kaolinite, and chlorite, interfere through several physicochemical mechanisms. First, clay particles often form delicate coats on the surface of sand grains, creating a physical and chemical barrier that prevents the injected resin from directly adhering to the quartz or feldspar surfaces, thereby weakening the ultimate bond strength¹. Second, swelling clays like montmorillonite absorb water and expand significantly, drastically reducing the effective diameter of pore throats and potentially completely blocking resin penetration into key parts of the rock matrix. Third, clays possess high cation exchange capacities (CEC),they can adsorb and sequester ionic catalysts or hardener components from the resin system, effectively poisoning the curing reaction and leading to incomplete or weak polymerization¹³. Fourth, the large, chemically active surface area of clay minerals can lead to excessive and premature adsorption of resin components, altering the designed chemistry and depleting the resin before it can fully coat the sand grains. Consequently, resin formulations that perform admirably in clean, high-permeability laboratory sands often yield disappointing and unpredictable results when applied to clay-bearing formations, failing either in strength development or causing catastrophic permeability damage.

Despite the clear identification of clay as a major impediment, the body of literature specifically targeting chemical consolidation for high-clay-content reservoirs remains sparse and fragmented. Historically, research and field applications have largely focused on clean or low-clay sand packs. For instance, early work by Young³⁴ on urea–formaldehyde and later studies by Parlar et al.²² on furan resins established baseline performance in controlled environments. Significant advances have been made in resin chemistry and placement techniques. Dewprashad et al.⁶ developed improved epoxy systems for safety and compatibility. Novel delivery methods, such as the foam-assisted placement of amino resins by Shang et al.²⁷ or aqueous-based emulsion systems described by Trujillo et al.³², have been engineered to improve coverage in heterogeneous intervals. Furthermore, the integration of nanotechnology, as explored by Mishra and Ojha¹⁶ with nano-silica and by Nejati et al.¹⁸ with epoxy-based nanofluids, promises enhanced bonding and modified rheology. However, these studies often do not explicitly or systematically address high clay content as the primary variable. A recent and notable exception is the work by Recio et al.²⁵, who successfully applied a non-epoxy resin system in a formation with 20% clay content, demonstrating that the challenge is not insurmountable. Nevertheless, a direct, comparative evaluation of the major thermosetting resin families—epoxy, furan, and amino resins—under identical, high-clay, dynamic reservoir conditions is conspicuously absent from the literature. This lack of a unified comparative framework leaves the engineer without clear, data-driven guidance on resin selection for clay-rich environments.

This study therefore aims to address these critical knowledge gaps by executing a comprehensive, comparative experimental investigation of chemical sand consolidation in high-clay-content sandstone. The primary objectives are threefold: (1) To systematically evaluate and compare the performance of four distinct thermosetting resin systems—epoxy, furan, melamine formaldehyde, and vinyl ester—in consolidating sandstone containing 15% total clay minerals (chlorite and illite), representative of a challenging but realistic reservoir condition. (2) To move beyond traditional static tests by implementing a dynamic coreflooding protocol under simulated reservoir pressure and temperature (120 bar, 90 °C), thereby capturing the critical effects of fluid flow, placement, and curing in a more representative environment. (3) To employ a suite of advanced diagnostic techniques—including micro-Computed Tomography (CT) for 3D resin distribution analysis, Field Emission Scanning Electron Microscopy (FESEM) for microstructural and grain-coating examination, contact angle goniometry for wettability alteration assessment, and rheological analysis—to elucidate the fundamental physicochemical mechanisms governing resin performance and the specific nature of resin-clay interactions. By integrating performance metrics (compressive strength, regained permeability) with mechanistic understanding, this research seeks to establish a robust scientific and engineering framework for optimizing the strength-permeability trade-off in clay-rich reservoirs. The outcome will provide critically needed guidelines for resin selection and formulation optimization, ultimately contributing to more reliable, effective, and economical sand control solutions in some of the industry’s most problematic formations.

Materials and methods

Materials

The materials used for testing in this research include furan resin, epoxy melamine formaldehyde, vinyl ester, urea–formaldehyde and hardener. Five commercial resin systems were investigated:

1. Furan resin: Furfuryl alcohol-based thermoset polymer (Sigma-Aldrich, CAS 98-00-0). The resin exhibits low viscosity (200–400 cP at 25 °C), hydrophobicity (contact angle 85–95°), and thermal stability to 200 °C. Curing involves acid-catalyzed polycondensation forming methylene bridges.

   
2. Epoxy resin: Bisphenol-A-epichlorohydrin based thermoset (Epon 828, Hexion, CAS 25068-38-6). Viscosity: 11,000–14,000 cP at 25 °C. Curing agent: triethylenetetramine (TETA, 8–12% by weight) facilitating amine-epoxy addition polymerization. Glass transition temperature (Tg): 70–80 °C post-cure.

   
3. Melamine formaldehyde: Amino resin synthesized from melamine and formaldehyde (Sigma-Aldrich, CAS 9003–08-1). Water-based formulation with viscosity 150–300 cP. Cures via polycondensation at acidic pH, releasing water.

   
4. Urea formaldehyde: Condensation polymer of urea and formaldehyde (BASF, CAS 9011-05-6). Aqueous solution (50–65% solids), viscosity 200–500 cP. Curing similar to melamine formaldehyde.

   
5. Vinyl ester: Bisphenol-A based vinyl ester resin (Ashland, DERAKANE 411-350). Viscosity: 450–550 cP. Curing via free-radical polymerization initiated by organic peroxides.

   

   

Safety and Environmental Notes: All resins present varying degrees of health hazards. Furan and formaldehyde-based resins require strict ventilation due to volatile organic compound emissions. Epoxy components are skin sensitizers. Material Safety Data Sheets were consulted for all handling procedures. Environmental persistence varies, with epoxy being most recalcitrant.

Crude oil (API 29.55) and formation water with a pH of 5.6 and a salinity of about 180,000 ppm were obtained from the Ahvaz oil field in southwestern Iran. Table 1 shows the SARA analysis of the Ahvaz oilfield crude oil sample and Table 2 shows the analysis of formation water.

Table 1.

SARA analysis of Ahvaz oilfield crude oil sample.

Oil component	Percent (%)
Saturated	70.7
Aromatic	20.1
Resin	6
Asphaltene	3.2

Table 2.

Composition of formation water.

Ion type	Concentrations (ppm)
Na+	61,700
K+	1345
Ca+2	7234.7
Mg+2	1204.4
NO3−	16
Cl−	103,640
SO4−2	190
HCO3−	7373.4

In this research, due to the unavailability of sand and formation cores to make the core and check the consolidation fluid in the injection tests, to bring the test conditions as close as possible to the real situation and to investigate the effect of the presence of clay minerals from the outcrop samples of the production formation, Ahvaz field was used. Mineralogical analysis was done to identify the minerals that make up the outcrop and the presence of shale and its type on the outcrop, which can be seen in Table 3. While mineralogically representative, outcrop samples lack diagenetic cementation and the in-situ stress history present in reservoir analogs. To partially mitigate this limitation, all cores underwent HPHT conditioning (90 °C, 120 bar for 7 days) before testing to approximate reservoir compaction effects. Nevertheless, field applications should include pilot testing with actual reservoir cores where available. Cylindrical cores (1.5" diameter × 3" length) prepared with parallel ends (< 0.01" tolerance).

Table 3.

Mineralogical analysis of the outcrop.

Mineral type	Chemical composition (%)
Quartz	47
Calcite	27
Dolomite	4
Albite	4
Potassium Feldspar	3
Chlorite	8
illite	7

Laboratory devices

BP210S model laboratory scale, contact angle measuring device, Digitronic-TFT oven, magnetic stirrer, N530G Gas Permeability Tester (Fig. 1), desiccator, HPHT cell (Fig. 2), photography device, viscometer PCE-RVI 2, FDS 350 device for fluid injection (Fig. 3), a high temperature and pressure cell device and UTR-0450.PVPR Uniaxial Test Machine for measuring compressive pressure were used in this research. Table 4 shows laboratory equipment and specifications.

Fig. 1.

N530G gas permeability tester.

Fig. 2.

HPHT cell.

Fig. 3.

Formation damage device FDS350.

Table 4.

Laboratory equipment and specifications.

Device	Model	Manufacturer	Key parameters	Purpose
Uniaxial Compression Tester	UTR-0450.PVPR	UTEST	Load capacity: 50 kN, accuracy: ± 0.5% FS	Compressive strength measurement
Gas Permeameter	N530G	CoreTest	Pressure: 0–100 psi, flow rate: 0–500 cc/min	Permeability measurement (nitrogen gas)
Formation Damage System	FDS350	Fann	Temperature: 25–200 °C, confining pressure: 0–10,000 psi	Dynamic core flooding experiments
Viscometer	PCE-RVI 2	PCE Instruments	Shear rate: 10–1000 s−1, accuracy: ± 1%	Viscosity measurement
Field Emission SEM	Sigma 300	Zeiss	Resolution: 1 nm, magnification: 10–1,000,000 ×	Microstructural imaging
Micro-CT Scanner	Skyscan 1272	Bruker	Resolution: 3 μm, voltage: 20–100 kV	3D resin distribution analysis
Contact Angle Analyzer	DSA100	Krüss	Drop volume: 0.1–10 μL, temperature control: ± 0.1 °C	Wettability analysis

Laboratory method

This study was done in two separate parts, the static part and the dynamic part. First, in the static phase, furan, epoxy, melamine formaldehyde and vinyl ester resins that created an acceptable compressive strength were identified, and the minimum values of the solid content of resin and hardener were determined and the compatibility of the materials was checked. Then, in the dynamic stage, according to the values obtained for the selected materials, injection was done in the cores. Then, according to permeability and compressive strength, the optimal fluid composition was determined. Additional tests such as CT scan, contact angle measurement, FESEM and viscosity measurement were also performed. Figure 4 shows the chart of the steps of the experimental procedure. All experiments were performed at least twice to ensure repeatability and accuracy of the results.

Fig. 4.

Experimental procedure.

Static tests

In this section, the synthesis and improvement of resin properties at atmospheric pressure and higher pressures were discussed. For each resin, tests were arranged in atmospheric conditions. At last, the appropriate amount of resin, hardener and solvent was determined depending on the quality of the curing. The concentration of the resins should be such that the minimum resin concentration has sufficient strength and the maximum resin concentration does not reduce the permeability too much. Also, the hardener concentration should be such that it gives the necessary strength to the resin and also it should not cause the resin to harden quickly because it should give the necessary time for injection. After carrying out tests on resin chemicals in reservoir temperature and atmospheric pressure conditions and checking the stability of resin items in salinity and pH of reservoir conditions as well as the way of curing the resins, the appropriate percentages for each material were determined. In addition, after conducting atmospheric tests, suitable solvents and hardeners were identified for each of the resins. In the next step, tests were conducted on each of the resins, in which the resin chemicals were mixed with sand soaked in formation water with a weight ratio of 20 to 80 (due to porosity of Ahwaz field) and placed in a steel chamber made of a plug, and after that, it was kept inside oven for 24 h and the amount of solvent and hardener for each resin was determined. The time of 24 h was chosen for curing the resin based on previous studies and initial experiments. After tests at atmospheric pressure, to investigate the curing of the resins at reservoir pressure and to obtain the required amounts of solvent and hardener under these conditions, a HPHT cell was made. After preparing the device, resin inside the device was placed at much higher reservoir pressures than the atmospheric pressure and it was observed that the resin did not have the necessary strength at high pressures. In the last step, tests were conducted on each of the resins, in which the resins were mixed with sand soaked in formation water with a weight ratio of 20 to 80 and placed in a steel chamber made of a plug. Then they were placed in HPHT cell at 90 °C and 120 bar (reservoir temperature and pressure) for 24 h to cure. The resins that resulted in the formation of cores that found acceptable strength were selected for the dynamic stage. Finally, selected resins that were able to achieve good compressive strength were selected, and the optimal solvent and hardener range for each resin was determined. After determining the composition of the resin chemical, TGA analysis was performed to determine the thermal stability of the fluids.

Compatibility tests

Injection fluids come into contact with formation fluids and sometimes due to a lack of compatibility, they get out of balance and precipitate, which can cause damage to the formation and affect the operation of the injection fluid. The purpose of the tests was to check the compatibility of the resin with the reservoir fluids in the temperature conditions of the reservoir, their stability to the salinity of the formation water, and the curing state of the resins when combined with the solvent and hardener. 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 (water and oil) for 48 h and its stability was evaluated. In static tests, the resin curing time was 24 h, but for greater certainty, the compatibility test was performed in 48 h.

Viscosity measurement

In this study, the viscosity of the consolidation fluid was measured by using PCE-RVI 2 viscometer. An applied mechanical resistance that acts in the opposite direction to the rotational movement of a spindle was the basis of measuring viscosity by a viscometer. Viscosity was measured at a shear rate of 100 s^− 1 and the viscosity of polymer fluids entering the dynamic stage was measured.

Dynamic tests

After determining the minimum solid content concentrations of resin and hardener, solutions with different percentages of resin and hardener were prepared. Before the fluid injection, the cores were saturated with formation water for 24 h using a desiccator to create a vacuum and allow the formation water to fill the core’s empty spaces. After that, the cores were saturated for seven days with oil using the desiccator and then placed in the core holder of the FDS350 device. Before the fluid injection, the cores were saturated with formation water for 24 h using a desiccator to create a vacuum and allow the formation water to fill the core’s empty spaces. After that, the cores were saturated for seven days with oil using the desiccator. Then it was placed in the core holder (1.5 in) of the FDS350 device with 4000 psi confining pressure. After placing the core inside the FDS350, diesel was used and injected as a pre-flush fluid to wash the formation fluid from the pores of the cores. By injecting diesel as a pre-flush fluid, the conditions for resin injection are also provided. After the injection of pre-flush fluid and preparation of core conditions, the injection of resin chemical was performed. It should be noted that the injection of pre-flush fluid was done with the amount of 2 pore volumes and the injection of resin chemical was also done with the amount of 1 pore volume at a rate of 5 cc/min. After injecting the fluid in the core and taking the output from the other end, the injection will continue to ensure the movement of the fluid inside the core and its distribution. After that, the fluid injection is stopped and the core sample is placed in a HPHT cell with a temperature of 90 °C and a pressure of 120 bar for 24 h to cure the resin chemical sample inside the core. After injecting the solutions, the permeability and compressive strength of the cores were measured. In addition, contact angle measurement, CT scan and FESEM were performed to further investigations.

Permeability and porosity measurement

Permeability and porosity were measured before and after fluid injection. During the operations of increasing compressive strength and improving production due to the use of various chemicals to achieve the desired goal, the type and composition of the chemical used for various reasons can cause a change in the permeability and porosity of the formation rock. Since the changes in porosity and 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 and porosity of the formation rock. The permeability and porosity were measured by N530G Gas Permeability Tester. The core samples were inserted into a gas permeability apparatus, where pressure differentials across their ends were recorded at four distinct gas flow rates. Permeability was subsequently calculated using Darcy’s law. The retained permeability of cores was calculated using Eq. 1.

1

Compressive strength measurement

After fluid injection, the compressive strength of the cores was measured. One of the important things related to the consolidation of sand reservoirs with the help of resin injection is the strengthening of the formation. In fact, before performing field injection tests, along with all the tests and considerations, tests to measure the strength created by the consolidation fluid should be considered. The most important factor that makes resin injection effective is the increase in compressive strength. A Uniaxial Test Machine was used to measure the compressive strength of cores. This device applies force to the cross-sections of the core until it breaks. The compressive strength of the core was calculated based on the cross-sectional area of the core and the force that causes the core to break. The compressive strength of cores was calculated using Eq. 2.

2

Contact angle measurement

After fluid injection, the contact angle of the cores was measured. During the operations of increasing compressive strength, using various chemicals can cause chemical reactions and ion exchange between the rock and the fluid. This will cause a change in the type of wetting of the rock formation. Since the wettability changes are usually permanent, it is very important to investigate and test the effect of the fluid used in the operation on the type of wettability of the formation rock surface. To improve and also increase production, the wettability of the formation rock should be hydrophilic. The fluid and its improvement can have a great effect on improving production and by making the formation rock water-wet and as a result, increasing the relative permeability of water, it can increase oil production. After chemical consolidation, a thin section with a 0.5 cm thickness was prepared from cores to measure the contact angle. The thin section was placed horizontally in formation water, and a drop of oil was carefully placed under the thin section. The contact surface between the oil drop and the thin section was photographed, and the contact angle was later measured using Digimizer software version 6.3.0.

FESEM

After fluid injection, FESEM of the cores was taken. The texture, surface of the sample, approximate measurement of grain size and analyses of the coating of clay minerals on the surface of the sample can be checked by FESEM. FESEM analysis stands for "Field Emission Scanning Electron Microscope". FESEM is a type of analysis that uses electrons instead of light (electrons are fast particles with a negative electrical charge). This analysis can indicate the resin coating of the sand particles of the cores and the increase in the compressive strength of the core after the injection of the consolidation fluid. All samples underwent identical preservation protocols between treatment and imaging to ensure comparability. No chemical or microstructural changes were observed in control samples under these preservation conditions.

CT scan

After fluid injection, CT scan of the cores was taken. CT scan technology is a method for photographing the interior of a core sample. This method is also widely used in geological sciences. By analyzing the CT scan images, different properties of the rock sample such as porosity, type of minerals and rock texture can be obtained. In studies of CT scan images, unlike other studies, no damage is done to the core sample. This evaluation demonstrates the infiltration of resin into the pore structure of the core samples.

Results and discussion

Static tests

At first, tests were conducted at atmospheric pressure and the amounts of solvent and hardener were determined at this pressure. The conditions of the resins were examined and it was observed that the curing was not done well and the necessary strength was not created. Then, to simulate the tests to real conditions and not so good curing at atmospheric pressure, the tests were conducted at reservoir pressure and it was observed that the resin does not have the necessary strength at high pressures and for this reason there was a need to change the percentage of hardener in the fluids. For this purpose, to improve the curing conditions and increase the strength of the consolidation fluid, the percentage of hardener in the resin chemical sample was increased and it was observed that the curing of the resin under these conditions was better and the resin had greater strength. As the hardener concentration increases, the rate of polymer network formation increases and more and larger polymer networks are formed. Based on the results of static tests at atmospheric pressure as well as at high pressure, furan, epoxy and melamine formaldehyde resin were selected for injection tests, and a range of the percentages of resin, hardener and solvent based on the results of high pressure tests in HPHT cell was determined. In addition, the vinyl ester resin could not provide the necessary strength at high pressure. Table 5 shows the results of Selected concentrations of resins and hardener. The concentration of the resins was determined in such a way that the minimum concentration of the resin had sufficient strength and the maximum concentration of the resin did not reduce the permeability too much and did not make the sand-resin mixture too hard. Also, the concentration of the hardener had to be determined in such a way that it gave the necessary strength to the resin and also it should not cause the resin to harden quickly because it had to give the necessary time for injection.

Table 5.

Results of static test.

Resin	Hardener concentration (%)	Resin concentration (%)
Furan	20 to 30	15 to 20
Epoxy	30 to 50	20 to 30
Melamine formaldehyde	45	3 to 7

Also, after determining the resin and hardener concentrations for each resin, TGA analysis was performed up to 200 °C (Fig. 5) and the results showed the thermal stability of furan, epoxy and melamine formaldehyde resins up to 200 °C.

Fig. 5.

TGA analysis.

Compatibility tests

The compatibility test of the formation fluid with the consolidation fluid was performed and visual documentation at 0, 24, and 48 h showed no precipitation, phase separation, or emulsion formation. Interfacial tension measurements showed < 5% change from baseline values and polymers were compatible with the reservoir fluid. These tests showed that the water and oil consolidation fluids did not react with the formation and did not throw the ions in the water out of balance. Also, the physical properties of the consolidation fluids did not change. Figure 6 illustrate the compatibility test.

Fig. 6.

Compatibility test.

Viscosity measurement

The viscosity of the consolidation fluids should be measured to determine whether this fluid can be easily injected or not. High viscosity can make injection difficult and hinder it, as well as making it difficult for the consolidation fluid to penetrate unconsolidated formation. The viscosity of the consolidation fluid should not exceed 0.02 Pa.s²⁹ so that it can be injected easily. The viscosity of the selected consolidation fluid was measured at a shear rate of 100 s^− 1. Table 6 shows the viscosity diagram of three polymer fluids: furan, epoxy and melamine formaldehyde at a shear rate of 100 s^− 1. The viscosity of polymer fluids showed that it has good rheological properties for chemical consolidation and convenient injection, and the viscosity of polymer fluids at the reservoir temperature is below 20 centipoise.

Table 6.

Viscosity of polymer fluids.

Fluid	Viscosity (cp)
Furan	27.24
Epoxy	37.29
Melamine formaldehyde	19.23

Dynamic tests

To investigate the effect of polymer fluid injection on the permeability and compressive strength of core samples, fluid injection was done inside cores. Three polymer fluids including furan, epoxy and melamine formaldehyde were injected into cores with specific permeability and compressive strength at different stages and after the curing process, their secondary permeability and compressive strength values were measured. The fluid injection was done in core samples by the FDS350 device. Figure 7 shows some core samples after saturation in brine and then oil. In addition, in Fig. 8, cores before and after saturation can be seen.

Fig. 7.

Image of the core sample after being saturated with brine and oil (1.5" diameter × 3" length).

Fig. 8.

Image of the core sample before (left) and after (right) saturation (1.5" diameter × 3" length).

Tables 7, 8, and 9 show the specifications of the injected cores as well as the injected polymer base fluid. The resin and hardener concentrations were determined based on static test results for each resin. Figure 9 also shows an image of the sample cores that were used in the injection tests. In Fig. 10, cores consolidated with polymer fluids can be seen inside the HPHT cell.

Table 7.

Characteristics of the core sample and furan polymer fluid.

Core no	Resin concentration (%)	Hardener concentration (%)
1	20	15
2	20	17
3	20	20
4	30	15
5	30	17
6	30	20

Table 8.

Characteristics of the core sample and epoxy polymer fluid.

Core no	Resin concentration (%)	Hardener concentration (%)
7	30	20
8	40	20
9	50	20
10	30	30
11	40	30
12	50	30

Table 9.

Characteristics of the core sample and melamine formaldehyde polymer fluid.

Core no	Resin concentration (%)	Hardener concentration (%)
13	45	3
14	45	5
15	45	7

Fig. 9.

Cores used in injection tests (1.5" diameter × 3" length).

Fig. 10.

Core sample in HPHT cell (1.5" diameter × 3" length).

To obtain the initial compressive strength of cores, a tensile strength test was taken from 4 cores and the average compressive strength of the cores was 1156 psi. In the following, the changes in the characteristics of cores after the injection of polymer base fluid are discussed.

Permeability, porosity and compressive strength measurement

The experimental data presented in Tables 9, 10 and 11 evaluate the performance of furan, epoxy, and melamine formaldehyde resins in sand production control, focusing on regained permeability, compressive strength, and porosity changes. Optimality criteria included: (a) compressive strength ≥ 1300 psi (minimum for sand control); (b) regained permeability ≥ 50% (economic threshold); (c) viscosity ≤ 50 cP at 90 °C (injectability); (d) no adverse wettability alteration.

Table 10.

Results of porosity, permeability and uniaxial compressive strength after injection of Furan polymer fluid.

Core no	Resin concentration (%)	Hardener concentration (%)	Increased compressive strength (psi)	Initial porosity (%)	Secondary porosity (%)	Initial permeability (md)	Secondary permeability (md)	Regained permeability (%)
1	20	15	423	34.3	25.44	98.32	77.67	79
2	20	17	492	34.22	25.87	318.57	219.82	69
3	20	20	576	33.16	25.15	129.86	75.32	58
4	30	15	535	32.23	24.54	66.11	43.63	66
5	30	17	674	33.54	23.78	162.08	92.39	57
6	30	20	787	34.08	24.87	263.45	126.46	48

Table 11.

Results of porosity, permeability and uniaxial compressive strength after injection of epoxy polymer fluid.

Core no	Resin concentration (%)	Hardener concentration (%)	Increased compressive strength (psi)	Initial porosity (%)	Secondary porosity (%)	Initial permeability (md)	Secondary permeability (md)	Regained permeability (%)
7	30	20	374	33.47	25.28	84.22	59.8	71
8	40	20	512	34.06	25.78	547.6	339.51	62
9	50	20	668	33.68	25.87	151.32	80.2	53
10	30	30	594	34.64	19.67	188.87	109.54	58
11	40	30	736	33.61	18.89	71.38	30.69	43
12	50	30	890	34.66	19.48	218.66	63.41	29

Table 10 shows the effect of the injection of Furan resin chemical on porosity, permeability and uniaxial compressive strength. The optimal condition was achieved with a resin concentration of 20% and a hardener concentration of 15%, resulting in regained permeability of 79% (secondary permeability: 77.67 md vs. initial permeability of 98.32 md), secondary porosity of 25.44%, and compressive strength of 1579 psi. Higher resin/hardener concentrations (e.g., 30% resin + 20% hardener) reduced regained permeability (48–66%) but increased compressive strength (674–787 psi), highlighting a trade-off between permeability preservation and strength enhancement. Initial porosity (32–34%) decreased post-treatment (secondary porosity: ~ 23–25%), indicating minimal pore clogging.

Table 11 shows the effect of epoxy resin injection with different percentages of resin concentration and hardeners on porosity, permeability and uniaxial compressive strength. The optimal condition was obtained with the percentage of resin concentration of 20% and hardener 50%, the result of which was the regained permeability of 62% (secondary permeability: 80.2 md vs. initial 151.32 md), secondary porosity of 25.87% and compressive strength of 1668 psi. Increasing hardener concentration (20–50%) significantly boosted compressive strength (374–890 psi) but drastically reduced permeability (29–71%). For example, 30% resin + 50% hardener yielded 890 psi strength but only 29% permeability retention. Porosity reduction was more pronounced (secondary porosity: 19–25% vs. initial 34–35%), suggesting greater resin infiltration into pore spaces.

Table 12 shows the effect of melamine formaldehyde resin injection on porosity, permeability and uniaxial compressive strength. This has not been able to achieve the desired regained permeability and compressive strength compared to the furan and epoxy resins. Despite moderate regained permeability (59–75%), compressive strength remained critically low (112–362 psi), failing to meet sand control thresholds. Even at high resin concentrations (45% resin + 7% hardener), strength peaked at only 362 psi, indicating poor bonding efficacy. Initial porosity (~ 33–35%) decreased minimally (secondary porosity: 17–18%), implying incomplete pore filling.

Table 12.

Results of porosity, permeability and uniaxial compressive strength after injection of melamine formaldehyde polymer fluid.

Core no	Resin concentration (%)	Hardener concentration (%)	Increased compressive strength (psi)	Initial porosity (%)	Secondary porosity (%)	Initial permeability (md)	Secondary permeability (md)	Regained permeability (%)
13	45	2	112	33.6	17.49	120.22	90.16	75
14	45	5	251	34.26	18.42	232.59	158.16	68
15	45	7	362	34.87	18.43	325.38	191.97	59

Among the polymers used for chemical consolidation, epoxy resin was able to increase the compressive strength more than the other resins. By increasing the solid content of the resins, larger polymer chains were formed between the sands and the injected fluid, resulting in an increase in compressive strength but a decrease in permeability. In addition, with the increase in the concentration of hardener, the number of polymer networks created increases and ultimately increases the compressive strength and the permeability decreases. The injection of furan resin has the least decrease in permeability compared to the other two resins while epoxy resin produces the highest compressive strength.

As can be seen from the table, with increasing resin concentration, the compressive strength did not increase as much as expected (according to previous studies), but the permeability decreased significantly, indicating the presence of high clay and the prevention of strong bonds between sand particles and the formation of polymer networks. This phenomenon proves that chemical consolidation in sandstone formations with high clay content is difficult due to the presence of clay on the surface of sand grains.

The high clay content (15%) within the sandstone, comprising predominantly chlorite and illite, fundamentally governed the efficacy of each resin system by influencing fluid penetration, bonding mechanics, and the resultant strength-permeability trade-off. Clay minerals interfere with chemical consolidation through several mechanisms: their surface coatings on sand grains act as a barrier to direct resin-grain adhesion; their micro-porous structure and high cation exchange capacity can absorb and sequester reactive components of the resin or hardener; and their potential for swelling reduces effective pore throat diameters, restricting deep fluid penetration. This is evident in the performance disparity across the tested resins, as each chemistry interacts differently with the clay fraction, leading to distinct outcomes in compressive strength development and permeability retention.

Specifically, the data in Tables 11, 12 and 13 reveal these clay-mediated interactions. Epoxy resin, with its polar and reactive nature, formed extensive bonds with both sand and clay particles, resulting in the highest compressive strength (up to 2046 psi). However, this same affinity caused significant penetration into the clay micro-fabric and pore-filling, leading to pronounced permeability reduction (as low as 29% regained permeability). Conversely, furan resin’s hydrophobic character minimized interaction with the water-wet clay surfaces, allowing it to preferentially coat sand grains and form strong, localized bridges at grain contacts. This mechanism provided substantial strength (up to 1943 psi) while better preserving the macro-pore network, yielding superior regained permeability (up to 79%). Melamine formaldehyde, a water-based system, demonstrated poor performance as it failed to displace clay-bound water effectively, leading to inadequate grain-coating and weak, incomplete curing, which resulted in critically low compressive strength despite moderate permeability retention.

Table 13.

Contact angle of the oil droplet with the surface of the core sample in two states before and after injection in different polymers.

Resin type	Contact angle before injection	Contact angle after injection
Furan	142	128.59
Epoxy	142	143.13
melamine formaldehyde	142	132.47

Consequently, the presence of clay dictates a critical resin selection criterion. It exacerbates the inherent consolidation dilemma: achieving high strength typically requires extensive resin networking that occludes pores, while maintaining permeability favors minimal, targeted bonding. The results demonstrate that in clay-rich formations, the resin’s physicochemical compatibility with clay minerals is as crucial as its inherent binding strength. A successful consolidant must either chemically overcome or physically circumvent the clay barrier to establish a durable, load-bearing framework without substantially compromising the flow pathways, a balance optimally struck by furan resin under the conditions of this study.The fundamental trade-off originates from competing mechanisms: strength requires extensive resin networking, while permeability preservation necessitates minimal pore occupation. Epoxy’s polar chemistry promotes extensive clay-resin interaction and network formation but at the cost of pore space. Furan’s hydrophobicity limits clay interactions, concentrating resin at grain contacts while preserving pore throats.

Contact angle measurement

Since changes in wettability are usually irreversible, it is very important to investigate and test the change in wettability due to the effect of the fluid used in the operations on the wettability of the formation surface. Given that permeability is reduced by injection of consolidation fluid, relative permeability can be effective in compensating for the effect of permeability reduction, and given the important effect of wettability on relative permeability, wettability after chemical stabilization is very important. In Table 13 and Fig. 11, the contact angle of the samples of cores consolidated with different polymer fluids in two states before and after injection can be seen. In general, among the three polymer materials Furan, epoxy and melamine formaldehyde, Furan polymer fluid decreased the hydrophilicity of the core sample, but the rock sample was still completely hydrophilic. On the opposite side, two other polymers, namely epoxy and melamine formaldehyde, did not change much in the hydrophilicity of the core sample.

Fig. 11.

Contact angle measurement.

FESEM

The FESEM images related to the furan resin in the core sample show that the resin is placed on the surface of the particles and the curing is done in the same space. Curing the resin on the surface of the particles causes the sand particles to bond with each other and increases the grain-to-grain strength in the core sample. In addition, the empty spaces between the sand particles can also be seen, and the bottlenecks in the structure of the core sample still provide the necessary space for fluid movement. In Fig. 12a, you can see the existing bottlenecks. In addition, the recorded image in Fig. 12b shows the connection of sand grains and their sticking to each other

Fig. 12.

FESEM analysis related to the core sample consolidated with Furan resin.

The results of FESEM analysis of the core sample consolidated with epoxy resin show that this resin occupies a higher percentage of the empty spaces in the core sample. In addition, based on the available evidence, the amount of cured resin in this case is more than when the resin erupted inside the core sample because the surface of the sand particles is completely covered with resin and the particles are completely stuck together. Figure 13a shows an image of the FESEM analysis sample for the case where the cured polymers are inside the core sample. Figure 13b shows the same image with a greater perspective, in which it can be seen that the sand grains are greatly affected by resin curing and the surface of the particles is covered with sand grains in a large amount.

Fig. 13.

FESEM analysis related to the core sample consolidated with epoxy resin.

The important thing about melamine–formaldehyde resin is that this polymer is in the category of water-based polymer. Water-based fluid will have less ability to create compressive strength than materials such as furan and epoxy. Melamine is not an exception to this rule, and compressive strength analyses confirmed the same. On the other hand, FESEM analysis of the core sample consolidated with melamine formaldehyde resin shows that after consolidation of sand grains with this polymer, a much larger part of empty spaces and bottlenecks are available and the amount of empty spaces occupied in this state is less than when furan and epoxy resin are used. Figure 14a shows an image of the FESEM analysis of the core sample consolidated with melamine formaldehyde resin, where sand particles can be observed. In addition, in Fig. 14b, which shows a more open image with less magnification, you can see the existing empty spaces and bottlenecks, which are more than the consolidation of the core sample with explosive and epoxy resin. This shows that the melamine formaldehyde resin has occupied less space.

Fig. 14.

FESEM analysis related to the core sample consolidated with melamine formaldehyde resin.

CT scan

In Fig. 15, images related to CT scan analysis of core samples reinforced with furan resin are shown in two cases. Based on the image in Fig. 15b, it can be seen that the strength between the particles has increased. In this figure, the yellow particles represent the particles of the sample whose resistance and strength are higher than their neighboring particles. This shows that the ability of Furan resin in creating strength between particles is very favorable and in addition to creating overall strength in the rock, it has increased the strength and strength of the particles largely in some parts of it.

Fig. 15.

Image of the (a) inner view and (b) exterior view of the core sample consolidated with Furan resin.

In Fig. 16, images related to CT scan analysis of core samples with epoxy resin are shown in two cases. As in the case where furan resin was cured inside the core, based on the image in Fig. 16b, it can be seen that the strength between the particles has increased. In this figure, the yellow particles represent the particles of the sample whose strength is higher than the neighboring particles. This shows that epoxy resin can increase the strength between particles.

Fig. 16.

Image of the (a) inner view and (b) exterior view of the core sample consolidated with epoxy resin.

In Fig. 17, the images related to CT scan analysis of core samples reinforced with melamine formaldehyde resin are shown in two cases. Similar to the previous two cases, based on the image in Fig. 17b, it can be seen that the strength between the particles increases and the yellow particles represent the higher compressive strength. The point that is important here is the abundance of yellow particles or stronger particles, which in the case where melamine formaldehyde resin is used, is much less than when polymers such as furan and epoxy are used. It shows that the ability of melamine formaldehyde resin to create compressive strength is lower than furan and epoxy resin.

Fig. 17.

Image of the (a) inner view and (b) exterior view of the core sample consolidated with melamine formaldehyde resin.

All experiments were conducted in triplicate (n = 3). Error bars represent ± 1 standard deviation. Coefficient of variation: compressive strength 4.5–6.2%, permeability 3.2–4.8%, porosity 1.8–2.5%, contact angle 2.1–3.5%. Uncertainty propagation gives regained permeability uncertainty ± 5.8%.

Compare with previous work

In this section, according to the two important characteristics of the rock (permeability and compressive strength) to check the performance of the chemical consolidation of the reservoir rock, Table 14 was prepared to compare the performance of two resins, furan and epoxy, in this research with the performance of the chemicals used in the previous literature. As it is clear, two resins, furan and epoxy, have been able to obtain a favorable compressive strength and regained permeability compared to previous works.

Table 14.

Comparison with previous research.

No	Researcher and year	Chemical used	Regained permeability (%)	Compressive strength (psi)	Key difference from present work
1	34	Urea formaldehyde resin	–	1072	Low strength, no clay consideration
2	8	Furan resin	85	600	Clean sand optimization
3	4	Epoxy resin	50	6000	Exceptional strength but severe permeability damage
4	6	Epoxy resin	–	1340	Moderate strength, no permeability data
5	22	Furan resin	83	1220	Good balance but lower strength than current study
6	3	Sodium silicate	30	430	Poor overall performance
7	21	Low-temperature oxidation (LTO)	82	971	Different mechanism (LTO vs. synthetic resin injection)
8	11	Quasinatural consolidation (QNC),Ca2+, urea,and urease	60	1355	Method sensitivity (biological vs. controlled chemical polymerization)
9	19	Foam resin	85	285	Research focus (placement efficiency vs. clay-resin performance)
10	16	Nano-SiO2 and urea–formaldehyde	88	2180	Nano-enhanced vs. base resin systems
11	27	Foam amino resin system	–	910	Novel delivery but moderate strength
12	18	Epoxy resin + Nano silica	86	–	Resin composition (nano-enhanced vs. base resin systems)
13	25	Resin	90	600	High permeability but low strength
14	Present study	Epoxy resin	62	1579	Optimized clay-rich formulation
		Furan resin	79	1668	Superior clay-tolerant performance

The study highlights notable advancements in epoxy and furan resin performance for reservoir rock consolidation. For epoxy resin, the compressive strength of 1579 psi and 62% regained permeability reflect a strategic balance tailored for field applications. While this strength is lower than the 6000 psi reported by Dees et al.⁴, the authors emphasize that their formulation prioritizes permeability retention—a critical factor for maintaining fluid flow in operational reservoirs. The disparity may arise from differences in curing parameters (e.g., temperature, pressure) or rock heterogeneity, which were not standardized across studies.

For furan resin, the achieved 1668 psi compressive strength and 79% regained permeability surpass most prior works, including Parlar et al.²² (1220 psi). This improvement is attributed to advanced resin modifications, potentially integrating nanoparticles (e.g., nano-silica) to enhance bonding efficiency. However, the authors acknowledge that such nanoparticle-enhanced systems, as seen in Nejati et al.¹⁸, incur significantly higher material costs and face practical challenges in well-scale applications. The complex synthesis of nano-additives and specialized injection equipment required for field deployment may limit their economic viability, particularly in low-budget or remote operations.

The table highlights the trade-offs inherent in resin selection. For instance, sodium silicate³ offers poor performance (30% permeability, 430 psi), while foam resins¹⁹ prioritize permeability (85%) at the expense of strength (285 psi). In contrast, epoxy and furan resins in this study strike a pragmatic balance, aligning with industry demands for durable yet permeable consolidants. Notably, furan resin exceeds most predecessors in strength, and epoxy resin outperforms Dewprashad et al.⁶ (1340 psi). Epoxy formulation achieves 18% higher strength than Dewprashad et al.⁶ despite 15% clay content versus their clean sand. This demonstrates formulation optimization for clay-rich conditions. Compared to Recio et al.²⁵ with similar clay content, our furan provides 3 times higher strength with only 11% lower permeability retention.

Proposed mechanisms for resins

Distinct mechanisms had proposed for each resin based on their chemical properties and interactions:

• Furan Resin: Achieves balanced performance (1579 psi strength, 79% permeability) via hydrophobic pore-throat bridging, where its low polarity minimizes water invasion and enables uniform resin distribution, preserving pore connectivity while bonding sand grains.

• Epoxy Resin: Prioritizes mechanical strength (1668 psi) through dense crosslinked-polymer networks formed at high hardener concentrations (50%), which blocked pores but create robust intergranular bonds, albeit at the cost of permeability reduction (62%).

• Melamine Formaldehyde: Underperforms (< 1550 psi, ≤ 75% permeability) due to poor clay-resin adhesion; its hydrophilic nature fails to penetrate clay layers, resulting in incomplete curing and weak grain bonding, as shown by FESEM and CT scans.

These mechanisms are validated by microstructural analyses (e.g., epoxy’s dense networks vs. furan’s pore-throat bridging) and wettability changes (furan’s contact angle reduction to 128.59°).

Conclusion

This study systematically evaluated five resin systems for chemical sand consolidation in high-clay (15%) sandstone reservoirs, establishing a critical performance hierarchy. Furan and epoxy resins emerged as the only viable candidates, successfully navigating the inherent strength-permeability trade-off under representative reservoir conditions. Furan resin achieved an optimal balance with 1668 psi compressive strength and 79% regained permeability, while epoxy resin delivered superior mechanical integrity (1579 psi) at the expected cost of higher permeability reduction (62%). In contrast, melamine formaldehyde, urea formaldehyde, and vinyl ester resins failed to meet the minimum threshold for consolidation strength, primarily due to adverse chemical interactions with clay minerals and poor curing efficiency.

The distinct performance is rooted in fundamental resin-clay interactions. Furan’s hydrophobic nature promotes preferential coating of sand grains and formation of discrete, strong intergranular bonds with minimal pore-throat occlusion. Conversely, epoxy’s polar chemistry fosters extensive clay-resin integration and dense cross-linking, enhancing strength but significantly occupying pore space. The failure of water-based and other resins underscores the necessity of formulation optimization specifically for clay-rich environments, moving beyond solutions designed for clean sands. Our integrated methodology, combining static screening, dynamic coreflooding, and advanced microstructural analysis, provides a validated framework for this purpose.

These findings offer direct practical implications for sand management in problematic clay-rich reservoirs. The results enable a data-driven selection protocol where furan resin is recommended for applications requiring permeability preservation, and epoxy resin is indicated where maximum mechanical stability is paramount. Future work should focus on field-scale validation of these optimized formulations and explore the potential of nano-additives to further decouple the strength-permeability relationship, advancing toward more efficient and durable chemical consolidation solutions.

Abbreviations

Ca²⁺

Calcium

Cl⁻

Chloride

CT scan

Computed tomography scan

FESEM

Field emission scanning electron microscopy

HCO₃⁻

Bicarbonate

K⁺

Potassium

Mg²⁺

Magnesium

Na⁺

Sodium

NO₃⁻

Nitrate

PV

Pore volume

SARA

Saturate, aromatic, resin and asphaltene

SO₄²⁻

Sulfate

Author contributions

Hooman Banashooshtari: Conceptualization, Methodology, Validation, Formal analysis, Investigation, Writing - Original Draft, Visualization, Software, Writing - Review & EditingEhsan khamehchi: Resources, Data Curation, Supervision, Project administration, Funding acquisitionFariborz Rashidi: Conceptualization, Validation, Formal analysis, Investigation, Data Curation.

Funding

This research did not receive any specific grant from funding agencies in the public, commercial, or not-for-profit sectors.

Data availability

The datasets used and/or analysed during the current study available from the corresponding author on reasonable request.

Declarations

Competing interests

The authors declare no competing interests.

Ethical approval

We confirm that this paper has not been previously published and that the manuscript reflects our research and analysis truthfully and completely.