Assessment of Formation Damage in Carbonate Rocks: Isolated Contribution of Filtration Control Agents in Aqueous Fluids

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The outcomes of this study support the design of optimized polymer-based well control fluids for reservoir zones in carbonate formations. By assessing the isolated and synergistic effects of filtrate-control agents, the results highlight additive combinations that ensure effective filtrate control while minimizing permeability impairment. This knowledge can conduct the formulation of environmentally compatible systems that enhance operational safety, mitigate formation damage, and contribute to maintaining reservoir productivity.

Abstract

Formation damage caused by wellbore fluids remains a key concern in carbonate reservoirs, where pore plugging and filtrate invasion can severely reduce permeability. This study investigates the influence of filtrate-control components in cellulose-based polymeric fluids on the potential for formation damage in carbonate rocks and evaluates the performance of HPA starch as an alternative to cellulose, focusing on its comparative effects on formation permeability. Experimental tests were performed using Indiana Limestone cores to measure filtration behavior and permeability recovery after exposure to different polymeric solutions. The results revealed distinct mechanisms associated with each additive: PAC LV controlled fluid loss mainly by adsorption and pore plugging, while HPA starch formed more deformable and permeable structures. Glycerin, when used alone, did not induce formation damage but increased fluid viscosity, favoring more stable dispersion of the polymeric phase. Micronized calcite enhanced external cake consolidation through particle bridging. The combined use of PAC LV, glycerin, and calcite provided the most efficient filtration control and minimized formation damage. These findings contribute to understanding the isolated and synergistic roles of filtrate-control agents and support the design of optimized polymer-based fluids for well intervention and abandonment operations.

1. Introduction

The safe and efficient execution of well operations such as drilling, completion, and workover requires the use of specially formulated fluids designed to control downhole pressure and ensure wellbore stability. These fluids act as hydraulic barriers, balancing formation pressures and preventing wellbore collapse. When in contact with the reservoir rock, it is critical that the fluid minimizes filtrate invasion while preserving the integrity of the producing zones [1].

Among the available types, water-based fluids with polymeric additives have gained prominence, particularly due to their ability to reduce filtrate loss, maintain rheological stability, and remain compatible with different operational environments [2,3]. Cellulose-derived polymers, such as carboxymethyl cellulose (CMC) and hydroxyethyl cellulose (HEC), show satisfactory performance combined with biodegradability, making them attractive alternatives for more sustainable formulations [4].

Despite these benefits, the introduction of polymer-based fluids into producing zones can induce several types of formation damage. Permeability reduction in the porous medium may result from mechanisms such as solids retention, pore blocking by polymers, wettability alteration, and undesired chemical reactions between fluid components and formation minerals [5]. Such effects compromise reservoir petrophysical properties, reducing well productivity and reinforcing the need for effective mitigation strategies.

These challenges highlight the importance of a careful selection of fluid components, prioritizing environmentally benign materials, as well as a thorough understanding of polymer behavior under operational conditions. It becomes essential to identify the agents potentially responsible for formation damage, particularly among additives used as fluid-loss controllers. A detailed characterization of the action mechanisms of each additive, along with an evaluation of their impact on permeability, allows distinguishing between effective filtrate control and undesired pore plugging [6,7,8]. This knowledge enables the development of optimized formulations capable of balancing rheological performance and filtrate control with minimal formation damage, ultimately improving well intervention efficiency and sustaining reservoir productivity.

Polymer-based fluids have long been associated with permeability impairment due to mechanisms such as extensional viscosity effects and pore-throat entrapment, as demonstrated by Maxey and van Zanten (2012) [9], including those formulated with cellulose derivatives. Complementary studies, such as that of Klungtvedt and Saasen (2022) [10], evaluated the damage induced by drilling fluids in permeable media, confirming the consistency of permeability variations obtained from controlled filtration tests. However, such approaches remain limited in distinguishing the individual contribution of each filtrate-control additive to the overall formation damage.

According to Sun and Chen (2025) [11], despite advances in diagnostic and predictive techniques, there is still a lack of detailed understanding of the physicochemical mechanisms underlying formation damage and their dependence on fluid composition.

Nevertheless, few studies have systematically evaluated the isolated and synergistic effects of these filtrate-control agents on carbonate formations, which constitutes the main research focus of this work.

Accordingly, this study investigates the influence of filtrate-control components in cellulose-based polymeric fluids on the potential for formation damage in carbonate rocks and evaluates the performance of HPA starch as an alternative to cellulose, focusing on its comparative effects on formation permeability.

2. Materials and Methods

The experimental procedures in this study comprised the petrophysical characterization of the rocks, formulation of the polymeric fluid with subsequent apparent viscosity measurements, and core flooding tests for return permeability to evaluate formation damage, all conducted under room conditions (25 °C).

2.1. Petrophysical Characterization of the Rocks

Cylindrical Indiana limestone cores (3 in. length × 1.5 in. diameter), commercially obtained from Kocurek Industries (Caldwell, TX, USA), were employed as representative samples of carbonate formations. As widely documented in the literature, they are mainly composed of calcite (CaCO₃). Chemical analyses usually report this composition in terms of oxides, with CaO equivalent values typically greater than 98%.

Porosity was determined by the mass difference between dry and brine-saturated conditions (KCl 4% w/v), and permeability was measured during the core flooding experiments.

2.2. Polymeric Fluid Preparation

A polymer-based fluid was developed for well control operations, with optimized filtration, rheological, and thermal stability. The base formulation is presented in

Table 1. Base formulation of the polymeric fluid.

Component
Deionized water
Antifoam
Sodium bicarbonate
PAC LV
Magnesium oxide
Crude glycerin
Saturated NaCl brine
Sodium hydroxide (to adjust pH = 10)
Micronized calcite (1–10 µm) (to adjust density to 10 lb/gal)
Glutaraldehyde

. During the development stage, it was observed that the primary agents responsible for filtrate control were the cellulose-based polymer (PAC LV, low-viscosity polyanionic cellulose, a commercial denomination for a type of carboxymethyl cellulose), while an increase in glycerin concentration also proved to be directly related to filtrate volume reduction.

2.3. Preparation of Solutions

To evaluate the influence of filtrate-control components on the potential for formation damage in carbonate rock samples, solutions were prepared containing, individually, the main additives involved in this mechanism. Additionally, a solution containing starch polymer (HPA) was formulated, maintaining the same PAC LV concentration used in the complete fluid formulation. The composition of each system is detailed in

Table 2. Composition of isolated-component solutions for filtrate control.

Solution	Composition
Glycerin + water	Crude glycerin 20% v/v
PAC LV + water	PAC LV 6 lb/bbl
PAC LV + water + glycerin	PAC LV 6 lb/bbl, crude glycerin 20% v/v
PAC LV + water + glycerin + calcite	PAC LV 6 lb/bbl, crude glycerin 20% v/v, micronized calcite (1–10 µm) 44.67 lb/gal
Starch + water	Hydroxypropyl starch (HPA) 6 lb/bbl

.

The solutions were prepared using a Hamilton Beach mechanical mixer, operated at medium speed. Additives were gradually incorporated into the aqueous medium under continuous stirring, maintaining a mixing time of 5 min after the addition of each component.

Following solution preparation (Table 2), apparent viscosity measurements were performed to characterize the rheological behavior of each system. Subsequently, all formulations were subjected to formation damage evaluation in carbonate rock samples through core flooding tests for return permeability assessment.

2.4. Apparent Viscosity (η)

The apparent viscosity (η) of the solutions and of the polymeric fluid was measured using a Thermo Scientific Haake Mars 60 rheometer equipped with a 35 mm serrated parallel plate geometry (P35/Ti/SB). Measurements were conducted at a constant shear rate of 170.3 s⁻¹. At the end of the tests, the acquired data were processed and analyzed using the RheoWin Data Manager software, version 4.91.0021.

2.5. Return Permeability Tests (Core Flooding)

Formation damage induced by the polymeric fluid and the individually prepared component solutions was assessed through return permeability tests, conducted with a Formation Damage System (FDS 350, DCI Corporation), following the methodology described by Barbosa et al. (2025) [12].

The system comprises an oil-free air compressor responsible for actuating the pumps and valves, and a high-precision VPA syringe pump (DCI Corporation) that injects distilled water into two accumulators. One accumulator contains 4% (w/v) KCl brine, while the other holds the test fluid (polymeric or individual solution), which is kept homogeneous by an integrated agitation system. The core holder applies a confining pressure compatible with reservoir conditions and ensures that the fluids are forced through the porous rock matrix, preventing any bypass around the sample. The flow lines and valves are arranged to allow axial flow in both forward and reverse directions through the core. Two pressure transducers (P1 and P2) are installed at the inlet and outlet of the core holder, while two differential pressure transducers (DP1 and DP2) monitor the pressure drop across the sample, enabling precise permeability calculation. A backpressure regulator (BPR) positioned at the end of the line maintains the system under pressure, simulating reservoir pore pressure conditions.

Each experiment comprised four main stages. In the first stage, the samples were saturated with 4% (w/v) KCl brine using an automatic saturator (Vinci Technologies, Nanterre, France). Initially, vacuum was applied to remove trapped air from the pore space, after which the chamber was filled with brine and pressurized up to 1000 psi for 2 h. The saturated samples were then stored in brine until testing.

In the second stage, the initial permeability (k_initial) was measured by injecting brine in the reverse direction at a flow rate of 2 mL/min until steady-state conditions were achieved, typically after the injection of approximately five pore volumes. This step represents the baseline permeability and simulates the natural flow of formation fluids toward the wellbore.

In the third stage, the test solution was injected under overbalance pressure, simulating the invasion of the polymeric fluid or its components into the rock. The solution was injected axially in the forward direction, applying an injection pressure of 1300 psi and maintaining a backpressure of 1000 psi, corresponding to a 300 psi overbalance. The invasion stage lasted 2 h, during which filtrate volume and pressure data were continuously recorded.

Finally, in the fourth stage, the permeability after fluid invasion (k_final) was measured by re-establishing the reverse flow of 4% KCl brine at 2 mL/min until steady-state was reached again, corresponding to approximately ten pore volumes injected. This step enabled the evaluation of the extent of formation damage and the calculation of the return permeability.

The return permeability (RP) and the corresponding formation damage (FD) were determined according to Equation (1) [12]:

$$FD\left(\%\right)=100-RP(\%)=100-\left({\displaystyle \frac{k_{final}}{k_{initial}}}\right)\times 100$$

(1)

In this equation, k_initial and k_final denote the initial and final permeabilities, respectively, and RP represents the return permeability expressed in percentage.

3. Results

This section presents the results obtained under laboratory conditions, encompassing the apparent viscosity of the polymeric fluid and component solutions, and the return permeability tests on carbonate rock samples. The analysis provides a comparative assessment of the influence of each constituent on filtrate control and formation damage.

3.1. Apparent Viscosity of Polymeric Fluid and Solutions and Return Permeability Tests

Table 3. Results obtained for apparent viscosity and for the return permeability test of the tested solutions and the polymeric fluid.

Sample	Porosity (%)	k Initial (mD)	k Final (mD)	Formation Damage (%)	Return of Permeability (%)	Filtrate Volume (mL)	Apparent Viscosity (cP)
Glycerin + water	16.93	28.56	28.56	0.0	100.0	73.0	1.76
PAC LV + water	19.35	44.81	11.15	75.1	24.9	16.7	267.64
	19.56	45.51	6.59	85.5	14.5	24.2
PAC LV + water + glycerin	16.89	26.24	6.56	75.0	25.0	13.1	358.01
	19.44	24.27	5.39	77.8	22.2	19.8
PAC LV + water + glycerin + calcite	19.65	40.46	25.74	36.3	63.7	5.2	468.98
	20.35	31.05	20.26	34.7	65.3	4.8
Polymeric fluid	19.29	26.77	21.97	19.8	80.2	3.3	447.28
	20.54	27.89	21.29	23.7	76.3	3.0
Starch + water	16.97	26.17	2.75	89.5	10.5	17.8	4.23
	19.58	43.47	1,32	97.0	3.0	24.8

summarizes the results obtained from the return permeability tests conducted with solutions containing different fluid components, along with the data for the polymeric fluid. The table reports the values of apparent viscosity, initial and final permeability, as well as the calculated percentage of formation damage and return of permeability (RP) for each sample.

3.2. Filtration Curves

Filtration behavior was evaluated by monitoring the filtrate volume as a function of time under constant overbalance pressure. The experimental data were plotted as cumulative filtrate volume versus the square root of time (Figure 1, Figure 2 and Figure 3), allowing the identification of the linear region typically associated with external filter cake buildup. For the glycerin + water system, no effective filtrate control was achieved; therefore, filtrate volume curves were not reported for this case.

3.3. Visual Inspection Results

Figure 4 presents the visual aspect of the solutions prepared with PAC LV + water and HPA starch + water. The PAC LV solution appears opaque, homogeneous, and visibly more viscous than the HPA starch solution, which shows a more translucent appearance.

Figure 5 presents the visual appearance of Indiana Limestone carbonate rock sample after return permeability tests with the polymeric fluid, while Figure 6 presents the appearance corresponding to the different tested solutions.

4. Discussion

This section discusses the experimental findings, with emphasis on the implications of the apparent viscosity measurements and permeability return tests for understanding the performance of individual additives and their combined effects on filtrate control and formation damage.

4.1. Apparent Viscosity of Polymeric Fluid and Solutions and Return Permeability Tests

The Indiana carbonate samples used in the tests exhibited a pore volume of approximately 15 mL. Based on the results presented in Table 3, the filtrate volume obtained for the solution composed solely of glycerin was 73 mL, indicating that the fluid permeated the entire rock sample without providing effective filtration control.

As demonstrated in previous stages of this study, glycerin plays a key role in reducing filtrate volume when incorporated into the polymeric fluid formulation. However, when used in isolation, it did not exhibit such capacity. This behavior can also be attributed to the very low viscosity of the glycerin–water solution, which favors flow through the porous medium under overbalanced conditions. In addition, the high affinity of glycerol molecules with water [13] contributes to their mobility during displacement with KCl brine. As a result, glycerin retained within the pores is easily solubilized and removed, preventing the plugging of the pore structure and, consequently, the occurrence of formation damage.

For the PAC LV solution in water, a more effective control of filtration was observed; however, the filtrate volume still exceeded the pore volume of the sample, indicating that the solution permeated the entire rock core. This behavior is partly attributed to the nature of the polymer, whose macromolecules tend to occupy rock pores and partially block them, which resulted in a formation damage level on the order of 80%. The use of polymers as filtrate-reducing agents in fluids that come into contact with the formation is often associated with formation damage, since these molecules can adsorb onto porous surfaces and form plugs that restrict or even prevent fluid flow toward the wellbore, as discussed [14]. In the specific case of PAC, its effectiveness as a plugging agent is related to its high adsorption capacity, which may lead to pronounced formation damage. This effect is further enhanced by the high molecular weight of the polymer, which promotes particle aggregation at pore surfaces, hindering their subsequent removal [15].

With the addition of glycerin to the PAC LV solution in water, the apparent viscosity increased by approximately 34%, resulting in a slight reduction in filtrate volume. Nevertheless, no significant decrease in formation damage was observed. The PAC LV + water + glycerin system exhibited an average formation damage of 76.4%, slightly lower than that of the PAC LV + water system (80.3%). This difference is likely related to the lower initial permeability of the carbonate cores used in this test (approximately 25 mD, compared with 45 mD in the previous one). Cores with lower initial permeability generally experience smaller relative reductions in permeability under similar testing conditions. Therefore, it can be inferred that the addition of glycerin substantially increased viscosity and modestly improved filtrate control, but did not significantly mitigate formation damage.

In the case of the solution composed of PAC LV, water, glycerin, and micronized calcite, a significant reduction in filtrate volume was observed, on average, about 69.7% compared with the previous case, along with a lower formation damage percentage of approximately 35.5%. The addition of solid particles was also responsible for a pronounced increase in the apparent viscosity of the solution.

It is noteworthy that the filtrate volumes measured in this test were lower than the pore volume of the rock sample, indicating that the fluid did not permeate the entire core length. This result suggests the formation of an effective filter cake on the rock surface. According to Ezell and Harrison (2008) [16], calcite demonstrates good performance in pore plugging, particularly when combined with polymeric solutions. In such systems, polymers form gel-like structures around the solid particles, promoting pore sealing in the near-surface regions of the rock, which results in the development of a thin, low-permeability filter cake.

The presence of calcite particles, in association with glycerin and PAC LV, exhibited a synergistic effect that ensured effective filtrate control, reduced the depth of invasion within the rock, and facilitated the partial removal of plugging particles. This combination not only decreased filtrate volume but also mitigated formation damage. Therefore, the integration of PAC LV, crude glycerin, and micronized calcite provided the system with performance characteristics comparable to those of the complete polymeric fluid, forming the functional basis of its filtration-control mechanism.

In the case of the HPA starch solution in water, the system displayed a markedly reduced apparent viscosity of only 4.23 cP, a value significantly lower than that of the PAC LV solution in water. Nevertheless, the average filtrate volume obtained was 21.3 mL, indicating a filtration control performance comparable to that of the PAC LV system. Although fluid viscosity is recognized as an important factor in controlling filtrate loss and invasion profiles in porous media [17], the results suggest that this phenomenon is more strongly influenced by the nature of the dispersed polymer.

According to Ghazali et al. (2015) [18], starch is employed as a filtrate-reducing agent due to its ability to obstruct rock pores with its macromolecules. This plugging effect arises from the relatively large size of its particles and their tendency to adhere to pore surfaces within the invaded zone. However, starch exhibits low efficiency in imparting viscosity to the system and is typically used in combination with viscosifying polymers to improve the rheological performance of fluids.

The aqueous starch solution tested showed a high degree of formation damage, with a permeability reduction of up to 97%. This result is related to the fact that the filtrate volume exceeded the pore volume of the sample, indicating that the fluid invaded almost the entire length of the core. Due to the adhesive action of starch particles throughout the invaded zone [19], the removal of material during displacement with brine was hindered, resulting in significant pore blockage and, consequently, a high degree of damage. This outcome is unfavorable for the use of starch in fluid formulations, which should be designed to cause the least possible damage to the formation.

4.2. Filtration Curves

The filtration behavior of the tested fluids is shown in Figure 1, Figure 2 and Figure 3, where filtrate volume is plotted against the square root of time, following the classical filtration model [17]. In all cases, the curves exhibit an initial linear segment, typically associated with the buildup of an external filter cake on the rock surface. At longer times, deviations from linearity become evident, reflecting contributions from internal filtration phenomena and partial plugging of pore throats. No filtration curve was obtained for the glycerin + water solution, as preliminary screening resulted in excessively high filtrate volumes and negligible formation damage, indicating that its inclusion would not provide meaningful insight into the comparative analysis.

For the HPA starch system (Figure 1), both tests showed a continuous increase in filtrate volume with time. The curve associated with the higher-permeability rock sample (red line) remained consistently above that of the lower-permeability core (black line), indicating more intense leakoff and a weaker sealing effect. This behavior agrees with literature reports showing that polysaccharide-based additives, such as starch derivatives, often provide limited filtrate-loss control under ambient conditions, with noticeable improvements only after thermal treatment [12]. The linear nature of the curves and filtrate volumes exceeding the pore volume of the cores corroborate the high formation damage observed for this system. This response can be attributed to the mechanism of damage associated with HPA starch: the polymer forms soft, deformable, and porous cakes that allow deeper fluid invasion into the pore network, promoting extensive internal plugging and significant permeability impairment.

In contrast, the PAC LV-based systems (Figure 2) exhibited a more effective filtrate control than starch, though with distinct outcomes depending on the presence of glycerin. For the PAC LV + water system, the filtrate volume exceeded the pore volume of the core, indicating polymer invasion and accumulation within pore throats, leading to substantial formation damage [20,21]. When glycerin was added, the curves showed lower slopes and reduced filtrate volumes relative to PAC LV alone. However, this attenuation is primarily linked to the higher viscosity of the system and the lower initial permeability of the tested cores, rather than to the formation of a superior filter cake. Thus, while glycerin contributed to leakoff reduction, it was insufficient to prevent internal plugging, consistent with the high damage values measured.

The most pronounced improvements were obtained for the PAC LV + glycerin + calcite system and for the complete polymeric fluid (Figure 3). The enhanced performance of these systems reflects the distinct but complementary damage-control mechanisms of each component. PAC LV, a cellulose-based polymer, forms low-permeability filter cakes mainly through molecular adsorption and partial pore plugging, effectively reducing filtrate flow but potentially limiting permeability recovery. Glycerin acts as a dispersant and plasticizer, improving the dispersion of solid particles and the mobility of polymer chains. This behavior has been widely documented in polysaccharide-based systems, where glycerol promotes intermolecular hydrogen bonding and increases the flexibility and homogeneity of the polymer matrix [22,23].

In the present context, its presence in the polymeric system containing dispersed solid particles contributes to the formation of more uniform and deformable filter cakes, reducing filtrate mobility and enhancing the continuity of polymer deposition on the rock surface. Micronized calcite, in turn, consolidates the external cake by mechanically bridging surface pores [24]. When combined, these additives exhibit a synergistic effect, as observed for the PAC LV + glycerin + calcite system, in which the balance between polymer adsorption, particle packing, and fluid-phase viscosity results in the formation of thin, compact, and low-permeability cakes. These cakes effectively limit fluid invasion and are easily removed during backflow, minimizing irreversible damage and promoting permeability recovery. In both the PAC LV + glycerin + calcite system and the complete polymeric fluid, filtrate volumes remained below the pore volume of the cores, and the curves tended toward stabilization, which is evidence of a well-structured sealing layer capable of controlling filtrate invasion [16].

Conversely, the starch + water and PAC LV + water systems maintained higher slopes and filtrate volumes, confirming their association with deeper invasion and more severe damage.

4.3. Discussion of Visual Inspection Results

The experimental observations reveal distinct behaviors for the tested polymeric solutions, even when prepared at the same concentration (6 lb/bbl). This distinction is visually evident in the appearance of the solutions (Figure 4). The PAC LV-based solutions exhibited a viscous and homogeneous aspect, while the HPA starch solution appeared notably thinner and less cohesive, reflecting their intrinsic rheological differences.

When these solutions were applied to carbonate plugs, contrasting surface responses were observed after the filtration stage (Figure 6). PAC LV-based systems demonstrated a pronounced ability to form a cohesive gel layer on the rock surface, corroborating the well-documented role of cellulose derivatives as effective filter-cake-forming agents in wellbore fluids [20,21]. In contrast, the HPA starch solution produced only a thin and discontinuous layer, which can be attributed to its lower viscosity and limited ability to build a structured cake [25,26].

These distinct behaviors can be explained by the molecular characteristics of the polymers and their interactions with the porous carbonate matrix. PAC LV is a linear cellulose derivative with relatively high molecular weight and strong adsorption on pore walls, forming compact and cohesive gels that effectively reduce filtrate invasion but may partially block pore throats [4]. Conversely, HPA starch, with a branched molecular architecture and lower molecular weight, generates a more deformable and weakly structured gel that tends to penetrate deeper into the pore network, increasing the likelihood of internal damage [25]. This mechanistic interpretation clarifies the differences observed in permeability recovery and supports the correlation between filtration curves and visual inspection results.

As observed in Figure 6a, the glycerin–water solution without PAC LV did not induce any significant filter cake formation, indicating that its contribution is primarily related to viscosity enhancement, with little participation in bridging mechanisms within the carbonate matrix [27]. On the other hand, as shown in Figure 6b and Figure 6c, the solutions containing PAC LV (PAC LV + water and PAC LV + water + glycerin) promoted the development of a more consistent gel layer on the rock surface, consistent with the typical behavior of cellulose-based polymers as cake-forming agents.

For the sample tested with the HPA starch + water solution (Figure 6e), a thin and weakly adherent film was observed, consistent with the low viscosity of the solution. Although insufficient to generate a thick external cake, this behavior leads to residual deposition on the surface, which may hinder complete permeability recovery [22].

Furthermore, the inclusion of calcite particles in the PAC LV + water + glycerin system led to visible deposition and consolidation of solids on the rock surface, even after KCl brine backflow (Figure 6d). The tested sample displayed a visual aspect closely resembling that obtained with the complete polymeric fluid (Figure 5), clearly evidencing the adhesion of calcite particles. This behavior aligns with the bridging and sealing mechanisms described for weighting materials, which can improve filter-cake stability and adhesion [24,28].

In the case of the PAC LV + water + glycerin + calcite system, although the rock surface was not uniformly covered, the filtration curves indicated effective filtrate control, suggesting that a compact and efficient filter cake had initially formed. However, the lower formation-damage values obtained for this system, combined with the irregular residue pattern, indicate that the filter cake was partially removed during the reverse brine flow. According to Rahmati et al. (2024) [29], besides the invasion depth of solid particles, the removability of the filter cake is an essential parameter for minimizing formation damage.

In this sense, the results suggest that the PAC LV + water + glycerin + calcite system formed a thin and easily detachable external cake, a feature directly associated with its lower damage levels. In agreement with the permeability data, the visual inspection confirms that the cooperative action of PAC LV, glycerin, and calcite governs the development of a stable yet removable filter cake at the rock–fluid interface, effectively restricting filtrate invasion while minimizing pore plugging [25].

5. Conclusions

This study demonstrated that the isolated evaluation of the main components of the polymeric fluid allowed for a clear identification of their influence on filtrate control and potential formation damage:

• The presence of glycerin in the solutions of polymeric fluid components promoted an increase in system viscosity but did not exert a significant influence on formation damage.
• The HPA starch polymer solution exhibited lower apparent viscosity, higher filtrate volumes, and more severe formation damage. These findings reinforce that the use of this material does not represent a suitable alternative to PAC LV in the formulation of fluids intended for direct contact with the reservoir, given its inferior performance and high potential to induce formation damage.
• The addition of micronized calcite, in synergy with PAC LV and glycerin, contributed to reducing formation damage and achieving more efficient filtration control. On average, the presence of calcite (together with PAC LV and glycerin) resulted in approximately 70% lower filtrate volume and 54% lower formation damage compared with the PAC LV + water + glycerin system.

Overall, this study shows that although the isolated evaluation of each component provides insights into their individual roles in filtrate control and formation damage, the synergistic combination of additives ultimately defines the performance of the polymeric fluid. In particular, the synergy between PAC LV, glycerin, and micronized calcite substantially reduced filtrate invasion and minimized formation damage. These results fill an important gap in the literature by systematically evaluating both individual and combined effects, and they provide a scientific basis for designing improved polymer-based fluids that enhance wellbore integrity, reduce damage mechanisms, and increase the efficiency of hydrocarbon production.