Polymer-based fluids for well workover: a comprehensive review

Abstract

Polymeric fluids are widely applied in workover operations because of their ability to control well pressure, regulate filtrate loss, and preserve reservoir productivity. However, their performance is highly dependent on polymer stability, since degradation under thermal, mechanical, or chemical stresses can compromise rheology, weaken filtration control, and increase the risk of formation damage. Research since the 1970s has advanced toward developing improved formulations, aiming to enhance efficiency while reducing reservoir impairment. Laboratory characterization techniques have been essential in evaluating polymer degradation and fluid–rock interactions, generating insights for polymer selection and fluid design. Within this context, this study proposes a literature review on polymeric fluids in workover operations, with emphasis on the role of polymers in fluid formulation and performance. The review also addresses operational fundamentals and technical challenges, focusing on thermal stability, degradation mechanisms, and strategies to minimize formation damage through adequate formulation and characterization approaches.

Keywords:
polymeric fluids; well intervention; thermal stability; performance

1. Introduction

Workover operations are performed throughout the productive life of a well for maintenance or technology updates. Although proper planning during construction reduces their frequency, periodic reviews remain essential to optimize production[¹,²]. These operations include activities such as zone cleaning, scale removal, casing and artificial lift maintenance, and efficiency adjustments[²-⁵].

Workover duration is influenced by operational complexity, resource availability, weather conditions, and regulatory constraints, and can vary from one day to several months[⁶-⁸]. In subsea (offshore) wells, additional challenges demand specialized planning and support. These operations involve higher costs due to environmental complexity, specialized equipment, and logistics[⁹], and must also comply with strict environmental regulations[¹⁰].

Before intervention, the well must be placed in a safe condition. This is achieved by well killing, in which a workover fluid is pumped into the well to provide sufficient hydrostatic pressure to counterbalance the reservoir pressure. As this fluid is pumped into the well, the existing wellbore fluids are displaced upward and circulated out of the well. In this way, workover fluids must control well pressures and filtrate loss while minimizing formation damage[¹¹-¹³].

The most common workover fluids are brines, often enhanced with solids or polymers acting as viscosifiers and filtrate-control agents[¹¹,¹⁴]. Among them, cellulose-based polymers such as hydroxyethyl cellulose (HEC) and carboxymethyl cellulose (CMC) stand out due to their performance and biodegradability[¹⁵-¹⁷].

In high-pressure and high-temperature (HPHT) wells, such as Brazil’s pre-salt fields, high temperature is a critical factor[¹⁸-²⁰]. Polymers and additives must resist degradation to preserve performance, since thermal effects can reduce their efficiency in providing viscosity to the fluids and controlling filtrate[¹⁵,¹⁶,²¹].

Since the 1970s, research has examined polymer-based workover fluids and concerns about formation damage[²²,²³]. With the growing relevance of HPHT interventions, issues of stability and durability have become more pressing, as degradation or viscosity loss can compromise fluid performance[¹⁵,¹⁷]. Recent studies have investigated PAC (polyanionic cellulose), a form of carboxymethyl cellulose (CMC) characterized by a high degree of substitution typically greater than 0.9, in well barrier formulations. In this range, the elevated degree of substitution enhances water solubility, hydration capacity, and viscosity, making PAC particularly relevant among the polymers commonly applied in high-performance workover fluids[¹⁶,²²-²⁵].

Given this context, this study reviews the use of polymeric fluids in workover operations, emphasizing their role in fluid formulation and performance. The review also addresses operational fundamentals and technical challenges, with focus on thermal stability, formation damage, and mitigation strategies.

2. Workover Operations

Workover operations comprise interventions performed during the productive life of a well with the purpose of maintaining integrity, restoring productivity, or adapting the well to new operational conditions. These activities include scale or paraffin removal, cleaning of production zones, maintenance or replacement of completion equipment, and operational adjustments to improve performance[¹-⁵].

The duration of workover operations varies according to the type of intervention, well configuration, availability of resources, and regulatory constraints, ranging from short-term activities to complex operations lasting several months[⁶-⁸]. In offshore wells, logistical limitations, higher operational costs, and stricter environmental regulations increase the complexity of planning and execution[⁹,¹⁰].

Prior to most workover activities, the well must be placed in a controlled condition through a well-killing procedure. This process involves circulating a specially designed fluid to provide sufficient hydrostatic pressure to balance reservoir pressure while displacing the fluids originally present in the wellbore. Under these conditions, workover fluids are essential to ensure pressure control and operational safety, while limiting fluid invasion and minimizing formation damage[¹¹-¹³].

3. Workover Fluids

Workover fluids are formulated to meet the specific requirements of the well and planned intervention, with functions that include controlling wellbore pressure, minimizing filtrate loss, and reducing formation damage[¹²]. The most common systems are brine-based fluids, which may be supplemented with minerals and polymers to enhance viscosity and filtrate control[¹¹,¹⁴]. In this regard, cellulose-derived polymers, particularly hydroxyethyl cellulose (HEC) and carboxymethyl cellulose (CMC), are extensively utilized owing to their ability to provide efficient viscosity enhancement and fluid-loss control, while maintaining good compatibility with reservoir conditions. Additionally, their water solubility, low toxicity, and susceptibility to biodegradation make them attractive from both operational and environmental perspectives[¹⁸].

During the design of workover fluids, attention must be given to the properties of the brine system employed. Ideally, brines should allow density adjustment over a broad range, be reusable, and contribute to shale inhibition. In addition, chemical compatibility between the brine and the formation rock is essential to avoid precipitation, scaling, or other adverse reactions. The compatibility of polymeric additives with the base fluid and formation is equally important, as inappropriate interactions may compromise fluid stability and overall performance[¹¹,²⁴].

In certain scenarios, particularly where wells are positioned in low-pressure zones, emulsion-based workover fluids emerge as a highly effective solution. These fluids consist of colloidal dispersions of water and oil, stabilized by surfactants. These formulations are suitable for such scenarios due to the presence of the oil phase, which results in a lower fluid density[¹].

Since the 1970s, the use of polymers in workover fluid formulations has been studied. Lipton and Burnett[²³] described the typical composition of these fluids, which combines a polymer solution containing polymers such as guar gum, HEC, and CMC with an inorganic salt. The polymers studied are ranked using the parameters of suspending ability (rheology), temperature/viscosity relationship, and stability to shear. According to those parameters, xanthan gum has presented the best performance.

Eaton and Smitey[²²] addressed formation damage as a critical concern in completion and workover operations. The authors investigated the reduction in formation permeability caused by different fluids and highlighted that fluid composition directly impacts the degree of damage. Backflow permeability tests revealed that fluid systems with low solid content or incorporating easily removable particles, such as acid-soluble materials, exhibited lower damage potential. In these systems, post-operation cleanup treatments, including acidizing, were effective in dissolving or dislodging the filter cake formed during operations, enabling partial recovery of formation permeability. The authors also compared various fluid systems and reported promising performance from newer formulations containing a complex lignosulfonate and sized calcium carbonate fluid loss additive, which resulted in minimal formation damage, with successful field applications documented.

Scheuerman[²⁶] contributed to the development of guidelines for using HEC polymer in solids-free completion and workover fluids. The author investigated the influence of different brines, including NaCl, CaCl₂, CaBr₂, and ZnBr₂, in combination with the polymer. The results showed that fluids containing HEC exhibited similar rheological and filtration performance regardless of the brine employed, maintaining stability at temperatures up to 48.9 °C and pH values as low as 6. These findings demonstrate the feasibility of using HEC-based systems under moderate temperature conditions across a range of brine compositions.

In the study conducted by Riley et al.[¹¹], the importance of considering the compatibility between workover fluid and formation lithology was emphasized. The researchers highlighted the risk of calcium carbonate precipitation when brines containing Ca²⁺ are used in workover fluid formulations for carbonate formations, since this cation reacts with the CO₃²⁻ anion from formation waters. This reaction leads to scale formation, which can obstruct the pores and channels of the formation, causing severe damage.

Thomas[²¹] investigated the thermal degradation of polymer-based fluids, considering the influence of temperature and exposure time. Fluid samples containing polymers, including CMC, were subjected to temperatures ranging from 37.8 °C to 232.2 °C. The half-life, defined as the time required for 50% degradation of the sample mass, was recorded for each condition. The results indicated that half-lives ranged from approximately 2 minutes to up to 95.2 years, the latter being estimated by extrapolation of the experimental data at lower temperatures. This highlights the significant influence of temperature on the degradation process of polymer-based fluids, underscoring the need to consider thermal effects in fluid formulation and application.

Ezzat et al.[²⁷] examined the vulnerability of polymers in workover fluids to microbial degradation, emphasizing that microorganisms can metabolize polymer chains as a nutrient source. Such degradation alters the polymer structure, leading to the loss of rheological properties and filtrate control, while also contributing to operational issues like corrosion, H₂S generation, and reservoir acidification. To address these risks, the authors stressed the incorporation of biocides as essential to protect polymer stability and maintain fluid performance.

Vollmer and Alleman[²⁴] analyzed the limitations of using HEC as a viscosifier and filtrate controller in workover fluids, comparing its performance with a “New Polymer” selected from ten candidates. The study employed ceramic disks as porous media to simulate formation permeability during progressive filtration tests. Formation damage was evaluated by measuring permeability before and after fluid saturation. The results showed a significant reduction in permeability for samples exposed to HEC, ranging from 65.7% to 79.0% of the initial permeability, whereas the new polymer exhibited lower permeability impairment under the same test conditions. The permeability reduction associated with HEC was attributed to formation damage at temperatures above 65 °C, particularly in the presence of NaCl or CaCl₂ brines.

Yang et al.[²⁵] evaluated formation damage in sandstone reservoirs using a polymer-based workover fluid and pore-scale X-ray CT analysis. By saturating a rock plug with formation water and then injecting the fluid, the study revealed swelling of clay minerals and fines migration. Rather than proposing a specific fluid formulation, the authors adopted a diagnostic and mechanistic approach, emphasizing that polymeric workover fluids must be compatible with the formation and capable of inhibiting the swelling of expansive minerals to minimize damage during interventions.

Recent studies have expanded the discussion on polymer-based fluids beyond classical workover formulations, focusing on strategies to minimize formation damage under well control conditions. Li et al.[²⁸] developed a high-density completion and workover fluid to reduce precipitation and emulsification, showing good stability, adjustable density (1.10–1.55 g/cm³), low filtrate loss (10.5 mL/30 min), reduced formation damage (8.7%), and successful field applications. This highlights that, alongside polymer-based approaches, additives such as mutual solvents and emulsifiers can also enhance performance and mitigate formation damage.

Complementarily, Lima et al.[²⁹] investigated polymer-based well-killing fluids formulated with carboxymethyl cellulose (CMC) in a glycerin-containing system, highlighting the role of formulation design in controlling filtrate loss and preserving formation permeability. The study also compared formation damage from CMC and HPA starch, showing higher damage with HPA. Although focused on well-killing operations, the mechanisms are applicable to workover fluids. These studies emphasize polymer–formation compatibility and filtration control, while performance differences reflect reservoir conditions and formulation strategies.

3.1 Workover fluids properties

The properties of workover fluids must be adjusted according to the needs of each well, so that the fluid exerts sufficient hydraulic pressure to withstand the pressure exerted by the formations, and has satisfactory rheological and filtration properties. Among the commonly analyzed properties, the following stand out:

3.1.1 Density

Before designing a workover fluid, it is essential to define the operational window, delimited by pore pressure (minimum) and fracture pressure (maximum) of the formation, ensuring section integrity. The fluid density must generate a hydrostatic pressure within these limits[³⁰].

For workover fluids, suspended solids are undesirable since static conditions may persist for days, increasing sedimentation risk and density gradients. Thus, inorganic salts are generally preferred to adjust density[¹]. Several types of salts are used in brines, selected by solubility to achieve target densities without solid dispersion[¹¹]. Monovalent salts (NaCl, KCl, NaBr, NaHCO₂, KHCO₂) yield densities from 8.4 to 11.0 lb/gal, whereas divalent salts (CaCl₂, CaBr₂, ZnBr₂) or blends can reach 14.0–19.2 lb/gal[¹]. Divalent brines also exhibit higher solubility, lower crystallization temperatures, and acidic pH, which should be corrected to alkaline to prevent corrosion and preserve polymers sensitive to acidity[¹,³¹,³²].

When brines alone are insufficient, solid weighting agents can be added in some cases. Barite (BaSO₄) is common in drilling fluids due to density (4.25 g/cm³) and inertness[³³], but under static conditions it settles, producing density gradients and operational risks such as sticking[³⁴,³⁵]. Sedimentation occurs faster in oil-based systems and more slowly in aqueous ones[³⁴,³⁵]. For this reason, barite is rarely recommended in workover formulations.

Calcite (CaCO₃) has been reported since the 1980s as a weighting and bridging agent[¹¹]. With specific gravity of 2.71 g/cm3[³⁶], it is less prone to settling than barite[³⁷]. Micronized calcite (~2 µm) reduces sedimentation and improves rheology compared to coarser particles (~40 µm) due to better dispersion[³⁸], making it more suitable for workover systems.

Another strategy involves incorporating glycerin into the liquid phase. With density of 1.26 g/cm³ (10.51 lb/gal), hydrophilicity, environmental compatibility, and favorable interaction with polymers, glycerin increases density while reducing formation damage, making it attractive for workover fluids[³⁹,⁴⁰].

For low-density applications in depleted zones, inverse emulsions (water-in-oil stabilized by surfactants) provide lower density than water-based systems[¹]. Mardashov et al.[¹³] reported densities of 0.950–1.420 g/cm³ (7.93–11.85 lb/gal), enabling precise adjustment. However, their high cost (synthetic oils) and environmental risks, particularly offshore, restrict their use to cases where the advantages outweigh the drawbacks.

3.1.2 Filtration

Once the fluid must exert sufficient hydrostatic pressure to prevent influx, its invasion into permeable formations is restricted by the development of a filter cake, which reduces permeability and fluid loss[⁴¹]. Filtration is predominantly static during intervention operations and is controlled by a progressive sealing mechanism in which larger particles initially bridge larger pore openings, initiating filtration control, while progressively smaller particles pass through remaining flow paths and complete the sealing process, resulting in a low-permeability filter cake[⁴²].

When polymeric materials are used as sealing agents in workover fluids, they can act through different mechanisms. One involves the formation of a gel or viscous layer on the rock surface. As the workover fluid interacts with the formation, hydrated polymer particles adsorb onto the rock, forming a layer that helps seal the pores and reduce fluid loss[⁴¹,⁴³].

Additionally, when solid particles are incorporated into polymer-based workover fluids, the polymeric gels aid in their retention and deposition at pore openings, creating a low-permeability structure. This structure acts as an additional physical barrier to control fluid loss and prevent unwanted migration within the formation[⁴¹,⁴³].

3.1.3 Rheology

In the context of workover fluids, rheology control plays a fundamental role. This property is essential to ensure efficient fluid pumping in the well and adequate filtration control. Additionally, the workover fluid must be capable of keeping solid particles suspended in the fluid column while facilitating their transport and removal[⁴⁴]. According to Guo et al.[²], in intervention operations, such as scale and paraffin removal, the fluid must efficiently dislodge and transport these materials.

Polymer molecules dispersed in aqueous media enhance viscosity by forming structured networks through molecular interactions and aggregates[⁴⁴]. Examples include xanthan gum, which adopts helix conformations to establish complex networks, as well as CMC, whose weakly bonded aggregates also contribute to viscosity enhancement[⁴⁴,⁴⁵]. These bonds are easily disrupted under shear, leading to temporary viscosity reduction that recovers once stress ceases, a behavior characteristic of non-Newtonian, pseudoplastic fluids[⁴⁶].

The addition of solid particles to polymeric solutions can increase viscosity due to polymer adsorption onto particle surfaces, improving particle suspension and fluid consistency. Ahmed & Belhadri[⁴⁵] showed that calcite addition significantly increases the consistency index (K) in polymeric fluids described by the Herschel–Bulkley model, while Nguyen et al.[³⁵] reported that smaller calcite particles exert a stronger effect on viscosity enhancement than larger ones.

Polymer conformation and intermolecular interactions are influenced by concentration, pH, ionic strength, and temperature, directly affecting viscosity and network formation. Changes in rheological behavior may also indicate polymer degradation, potentially leading to precipitation, flocculation, or microgel formation, which can impair fluid performance and increase formation damage risk[⁴⁶-⁴⁸].

3.2 Polymeric additives

To enhance the performance of workover fluids during well interventions, various additives can be used. These additives are selected based on the well requirements and can improve fluid performance, particularly in situations where the fluid remains static in the well for extended periods.

When selecting polymers, it is important to consider their molecular structure as well as the required properties of the fluids under application conditions, especially in deep wells with high temperatures and pressures[⁴⁶]. Additionally, it is essential to ensure that the choice of polymers meets environmental requirements[⁴⁷].

In general, polymers used in the formulation of well fluids have high molecular weight and polar functional groups, which enable them to adsorb water molecules and increase fluid viscosity. This increased viscosity helps improve the transport and suspension of solid particles present in the fluid. Furthermore, these hydrated particles can deposit on the surface of rock formations, aiding in pore plugging and contributing to fluid loss control to the formation[⁴⁸].

In polymer-based fluid preparation, pre-hydration is commonly applied, allowing the polymer to fully absorb water and reach optimal solubilization before the addition of brine and other components, resulting in the final formulation[²¹]. Polymers used in fluid systems may undergo degradation when exposed to high temperatures and pressures, particularly during prolonged operations, leading to changes in their chemical structure and rheological behavior. Therefore, the selection of thermally and chemically stable polymers is essential to minimize performance losses under well conditions[⁴⁹].

In response to increasing environmental concerns, biopolymers derived from cellulose, starch, and xanthan gum have gained attention and demonstrated effectiveness in improving the rheological and filtration properties of oilfield fluids[¹⁵].

Polymeric additives are commonly marketed in powder form and may consist of mixtures of different polymers or combinations of polymers with inorganic materials[⁵⁰]. Among the polymers used in workover fluid formulations or those with potential for such applications, some stand out due to their properties and associated challenges. In the 1970s, guar gum (GG) was widely used in workover and completion fluids due to its non-ionic nature, making it compatible with a wide range of electrolyte concentrations[²⁰]. However, high concentrations of multivalent salts can compromise its hydration, leading to gel formation that may cause formation damage[⁵¹]. Although guar gum is still used in completion fluids[⁵²], it is more frequently applied today in hydraulic fracturing fluids, where the polymer and its derivatives play a fundamental role[⁵¹,⁵³-⁵⁶].

Xanthan gum (XG) is widely used as a viscosifier and filtrate controller in drilling, completion, and workover fluids due to its low formation damage potential. However, it is sensitive to high temperatures and contaminants, requiring stabilizers and strict control of fluid purity[⁵⁷]. Above 100 °C, its molecular structure undergoes irreversible changes that drastically reduce viscosity, and at temperatures above 120 °C, shear stress approaches zero, indicating loss of functionality[⁵⁸,⁵⁹].

The polymer hydroxyethyl cellulose (HEC) has been widely used in completion fluid formulations since the 1970s and gained popularity in workover fluids during the 1980s[²¹]. The authors highlight the importance of pre-hydration techniques for certain high molecular weight polymers. This step allows for the efficient incorporation of HEC into high-density brines. Thus, HEC has emerged as a commonly employed fluid loss control agent in well intervention operations.

The polymer HEC can be used in brines containing NaCl, NaBr, KCl, NH₄Cl, CaCl₂, and CaBr₂ under a range of density and pH conditions and at moderate temperatures. Under typical oil well conditions, published data indicate that HEC causes minimal formation damage and provides predictable rheological behavior when properly prepared[⁴⁴].

HEC presents some limitations regarding its use. Performance issues commonly addressed in studies focus on dispersibility, hydration rate, high-temperature rheology, and formation damage[²¹]. As observed by Hodge[⁴⁸], increasing the temperature in HEC-formulated fluids can lead to polymer precipitation, especially when combined with NaCl or KCl brines at temperatures above 65.6°C. This precipitation can compromise the fluid's rheological properties, negatively affecting its performance.

Furthermore, it is widely recognized that the use of HEC gels can cause formation damage, such as fish eyes (unsolvated polymer particles), microgels, and viscous pore plugging in rock formations. Therefore, proper preparation and use of fluids containing HEC are crucial to minimizing or eliminating formation damage associated with its use[⁴⁴].

The application of sodium carboxymethyl cellulose (CMC) as a drilling fluid additive is well-documented, particularly in combination with bentonite and calcite (CaCO₃). This combination is reported in several studies highlighting its effectiveness in various fluids compositions[¹⁵,⁶⁰-⁶⁷]. Teymoori & Alaskari[⁶⁸] also emphasize the superior performance of CMC over other alternatives, such as xanthan gum, in filtration control.

Sodium CMC, in its high-degree substitution form (greater than 0.9), is widely known as polyanionic cellulose (PAC). This derivative has been extensively used in drilling fluids, particularly to enhance rheological and filtration properties[¹⁶,⁶⁹-⁷⁴]. Although specific evidence of its application in workover fluids is limited, PAC has been successfully employed as a filtrate reducer in drill-in fluids[⁷⁵-⁷⁷] and in completion fluids[⁷⁸,⁷⁹], systems designed to minimize formation damage.

Pioneering studies, such as those by Lipton and Burnett[²³] and Carico[⁶⁹], highlighted the benefits of CMC in workover formulations, laying the foundation for its current relevance. More recently published investigations expanded the understanding of the potential of CMC derivatives, such as PAC, in optimized barrier formulations for temporary well abandonment[¹⁵,¹⁷]. Notably, Gonçalves et al.[¹⁷] emphasized that fluids based on PAC, when prepared with an optimized polymer content, can deliver satisfactory performance in controlling well pressures during temporary plug and abandonment operations. Importantly, this performance was maintained even when the polymer was hydrated in saline media to increase fluid density, without the addition of mineral solids. This outcome strengthens the evidence that PAC is not only viable for drilling and abandonment fluids, but also a highly promising polymeric base for workover formulations, where maintaining well control under severe conditions is equally critical.

4. Degradation of Polymeric Fluids

Polymers used in workover fluids are susceptible to degradation, which can compromise fluid performance. Degradation occurs primarily due to exposure to high temperatures and the microbial activity.

4.1 Effect of temperature

In deeper wells, such as offshore wells in Brazil's pre-salt layer, high-pressure and high-temperature conditions are common challenges. These wells can reach depths of up to 5,000 meters, with typical static pressures of up to 50 MPa, following a pressure gradient close to 0.01 MPa/m. Additionally, due to the geothermal gradient, temperatures in these wells can exceed 120 °C[¹⁵,¹⁶]. As a result, well intervention operations under these conditions require workover fluids capable of withstanding such extreme environments.

Thermal stability is a decisive factor in fluid selection, since rheological and filtration properties depend on the preservation of polymers and additives[¹⁶]. Polymer degradation reduces viscosity and compromises filtrate control, directly affecting operational efficiency[¹⁸]. As verified by Thomas[²¹], the thermal decomposition of polymers such as CMC is influenced by both temperature and exposure time. Mohamed et al.[¹⁸] found that CMC shows higher thermal resistance (149 °C) compared to GX (121 °C) and HEC (96–99 °C), with viscosity losses attributed to hydrolysis and oxidation.

Recent studies reinforce this perspective. Costa et al.[¹⁵] investigated the degradation of a polymer-based fluid under different temperature conditions, showing that rheological properties and filtrate control were only compromised above 140 °C due to CMC degradation. The study is notable for applying accelerated life tests to estimate the fluid’s expected lifespan under operational conditions, providing a methodological advance for the qualification of liquid barriers in temporary abandonment. Complementarily, Farias et al.[¹⁶] pointed out the correlation between rheology and thermal degradation of CMC solutions, indicating that viscosity loss precedes structural decomposition and directly affects filtration performance. Collectively, these findings demonstrate that the design of polymer-based workover fluids must take into account not only their initial performance but also their thermal stability over time, ensuring reliability in HPHT environments.

4.2 Microbial activity

In the context of petroleum wells, the degradation of fluids formulated with natural polymers due to microbial activity is a significant concern. The polymers present in these fluids, such as GX, CMC, and HEC, can be degraded and utilized as nutrients by microorganisms, primarily bacteria, leading to contamination of reservoir zones near the wellbore[⁷⁸,⁷⁹].

Microbial growth can cause issues such as equipment and pipeline corrosion, as well as the release of hydrogen sulfide (H₂S) and reservoir acidification. Additionally, extensive microbial proliferation leads to significant degradation of the polymers present in the fluid, resulting in the loss of their rheological properties and the ability to control fluid loss to the formation[⁷⁹,⁸⁰].

According to Al-Humam et al.[⁷⁸], biocidal substances are added to fluids to combat microbial activity. However, the effectiveness of these agents may be limited. It is important to select biocides that are compatible with the fluid components, effective against target microorganisms, and stable under downhole conditions. Some examples of effective biocides include aldehydes, isothiazolone, and quaternary phosphonium salts.

Maintaining an alkaline pH (typically between 9 and 11) is also an approach to mitigating microbial activity, as most microorganisms responsible for these issues do not thrive in environments with a pH above 9[⁷⁷,⁸⁰]. Therefore, the appropriate selection of biocides and pH control are essential to prevent microbiological damage, preserve the integrity of workover fluids, and ensure satisfactory performance during operations[⁸¹].

4.3 Material characterization techniques applied to polymer degradation in fluids

The degradation of polymeric fluids can be assessed through a variety of material characterization techniques. These techniques, commonly employed in drilling fluids, can also provide valuable insights into the changes in the physical, chemical, and structural properties of polymers over time in workover fluids.

Fourier Transform Infrared Spectroscopy (FTIR) is a technique that analyzes the interaction of molecules with infrared radiation. It can be used to identify functional groups present in polymers and to monitor changes in the chemical structure caused by degradation. By comparing spectra obtained before and after degradation, it is possible to identify the formation of new functional groups or the modification of existing ones[⁸²].

Thermogravimetric Analysis (TGA) measures the mass variation of a material as a function of temperature. In the context of polymeric fluid degradation, TGA provides information on the thermal stability of polymers and identifies the temperature ranges in which degradation occurs. From the mass-loss curve as a function of temperature, it is possible to determine the onset temperature of degradation, the degradation rate, and the overall thermal stability of the material[⁴⁵].

Gel Permeation Chromatography (GPC) is used to determine the molecular weight distribution of polymers. It is widely applied to detect changes in polymer molecular weight as a result of degradation. By comparing molecular weight distribution profiles before and after degradation, it is possible to identify reductions in average molecular weight as well as the presence of degraded fragments[⁸³].

The Zeta Potential technique characterizes the surface charge and stability of colloidal dispersions by measuring the electrical potential at the interface between dispersed particles and the medium. Negative values indicate strong electrostatic repulsion and stable dispersions, while values near zero or positive suggest low stability with greater tendency to agglomeration or sedimentation[⁸³,⁸⁴]. This technique is widely applied in polymeric fluid studies to assess dispersion stability and performance under different conditions[⁸⁴].

Material characterization techniques can be combined to map the behavior of polymers in fluids, considering the specific operational conditions to which they are subjected.

Xie et al.[⁸³] investigated the stability and rheological behavior of drilling fluids for deepwater applications under varying temperature conditions. A synthetic thermosensitive polymer (PANA) was characterized using FTIR, elemental analysis, and GPC, while rheological and zeta potential measurements were employed to assess the effects of temperature on fluid stability and viscosity. The results provided insights into fluid performance under thermally challenging conditions.

In the study by Li et al.[⁸⁵], a physicochemical characterization of a PAC-based polymer system was performed to investigate hydration mechanisms using XRD, DSC, FTIR, zeta potential, and rheological analyses. The authors concluded that PAC hydration is driven by hydrogen bonding between water molecules and polymer hydroxyl groups, forming an interconnected structure. These techniques were also shown to be suitable for monitoring structural changes associated with polymer degradation induced by thermal or microbial effects, although no specific operational temperature limits were established.

In the work written by Huang et al.[⁴⁹], the effect of laponite nanoparticles on the thermal stability of water-based drilling fluids was evaluated. Using thermogravimetric analysis and high-temperature rheological tests on fluids containing the AAD terpolymer, results revealed a high decomposition temperature (370 °C) for this polymer. This finding suggests its potential application in high-pressure and high-temperature wells, where thermal stability is a critical requirement.

Farias et al.[¹⁶] advanced this line of research by evaluating the thermal degradation of carboxymethyl cellulose (CMC) in saline solutions, combining SEM, FTIR, TGA/DTG, DSC, and rheological tests. Their findings demonstrated that viscosity loss can precede thermal decomposition, evidencing the importance of correlating chemical stability with rheological performance in the evaluation of fluids for petroleum wellbore applications.

In high-pressure and high-temperature wells, such as those in Brazil’s offshore pre-salt fields, it is crucial to ensure the thermal stability of workover fluids. Thermal stability prevents significant polymer and additive degradation, thereby preserving fluid properties and performance[¹⁹,²⁰]. Polymer degradation can reduce the operational efficiency of the fluid, compromising its functionality under demanding conditions. Therefore, the proper selection of workover fluids with high thermal stability is essential for the success of operations in high-pressure and high-temperature wells.

5. Formation Damage

In addition to adjusting the appropriate properties and selecting components that remain stable throughout the intervention period, workover fluid must be carefully designed to ensure that its interaction with reservoir rocks does not cause formation damage.

Formation damage refers to changes in rock structure and in its petrophysical or mechanical properties caused by fluid invasion during drilling, completion, or workover operations. These changes, such as reduced porosity, permeability, or altered wettability, can significantly impair well productivity or injectivity[⁸⁵].

This damage can occur due to various factors, including mechanical effects, chemical effects, or extreme temperatures associated with thermal recovery methods[⁸⁶,⁸⁷]. Among these, mechanical and chemical effects are most strongly associated with the fluid used for wellbore stabilization[¹].

The mechanical effects causing formation damage are related to the mobilization of solid particles carried by the fluid during invasion. This mechanism can result in pore blockage, reducing the formation’s permeability and affecting hydrocarbon production. The migration of solids into the formation occurs when a low-permeability filter cake is not effectively formed, allowing fines to migrate into the formation[⁴⁹].

Although a low-permeability filter cake is desirable, it can also cause formation damage. The cake must be thin and removable; otherwise, hydrocarbon flow to the wellbore after the intervention may be restricted. Bentonite, widely used for viscosity and filtrate control, often forms filter cakes that are more difficult to remove than those made with polymeric materials, increasing the risk of damage. For this reason, avoiding clay minerals in workover formulations is generally preferable[⁸⁸,⁸⁹].

Calcite particles are widely used as bridging agents due to their availability in various sizes and their effectiveness in pore plugging. When combined with filtrate-reducing polymers, a synergistic effect occurs as polymer chains form a network around calcite particles, producing a thin, low-permeability filter cake. Moreover, calcite is acid-soluble, which facilitates filter cake removal and helps restore formation permeability[⁹⁰].

Chemical effects are directly related to the chemical compatibility between the fluid used, the rock formation, formation water, and the hydrocarbon compositions present[⁸⁶]. Chemical incompatibility among these elements can cause significant formation damage. One of the main issues is the swelling and migration of clays within the formation, which can block pores and reduce reservoir permeability[²⁵].

Scale formation is another issue, often linked to brine composition. When brines with Ca²⁺ interact with carbonate ions in formation water, calcium carbonate (CaCO₃) precipitates in the pores, reducing permeability and fluid flow[¹,¹¹,⁸⁶].

Polymers used in workover fluid formulations can also present challenges related to formation damage. These polymers can adsorb onto rock surfaces, forming plugs that restrict or even completely block flow toward the wellbore. Additionally, polymer incompatibility with other chemicals may lead to the swelling or dispersion of clay minerals, further reducing permeability[²⁰]. To avoid or minimize these problems, optimizing the polymer concentration used in workover fluids is essential. It is also important to select polymers that are less harmful to the specific formation characteristics. If necessary, stabilizing additives can be used to improve chemical compatibility between polymers and the formation, preventing permeability reduction[⁸⁶,⁹¹].

5.1 Formation damage mitigation

According to Patel and Singh[⁹²], formation damage causes annual losses of billions of dollars due to production delays, corrective treatments, and irreversible reservoir losses. Thus, prevention is essential, and when not possible, diagnosing, assessing, and remediating the damage become key challenges for efficient and profitable hydrocarbon recovery.

Damage caused by wellbore fluids, particularly from polymers, can be mitigated through different approaches. One method is acidizing, in which acid solutions dissolve or break down polymer-related damage within the formation, restoring permeability[⁹²].

Surfactants and gel breakers also play an important role. Surfactants reduce interfacial tension and disperse polymer residues, while gel breakers degrade crosslinked structures, lowering viscosity and reestablishing permeability. Their effectiveness, however, depends on fluid composition and the type of damage encountered[⁷³,⁹³].

The selection of a remediation method depends on factors such as damage type, lithology, and reservoir conditions[⁹⁴,⁹⁵]. Rahmati et al.[⁹⁶] tested the LPM-FBR additive in fractured sandstone, showing its capacity to reduce fluid invasion and seal fractures under high overbalance. However, it also induced significant damage, underscoring the challenge of designing polymer-based systems that balance filtrate control with permeability recovery in fractured reservoirs.

6. Conclusions

Aiming to conduct a comprehensive literature review on the use of polymeric fluids in workover operations, addressing operational fundamentals, polymers used in these fluids, and technical challenges related to their thermal stability and formation damage.:

• The selection of polymeric additives in workover fluids requires careful consideration of their molecular structure and functional properties to ensure fluid stability under well-specific conditions, while also minimizing the risk of formation damage.

• Polymer degradation can compromise workover fluid performance, especially in offshore wells, where high temperature and pressure demand additives with high thermal resistance to preserve their properties during operations.

• In addition to thermal effects, the polymers in workover fluids are subject to degradation caused by microorganisms. Therefore, appropriate biocidal agents should be used to slow down this process during fluid application;

• Formation damage caused by workover fluids can be minimized through the careful selection of polymers and sealing materials, ensuring efficient sealing and controlled removal. To achieve this, fluids must balance fluid loss control with permeability preservation.

This review emphasizes that polymer stability under reservoir conditions is essential for the performance of workover fluids, ensuring rheological control, filtrate management, and preservation of formation properties. Therefore, careful selection and characterization of polymers are essential for developing formulations that remain effective throughout operations.

8. Acknowledgements

This research was funded by PETROBRAS, grant number 0050.0120134.21.9.

• Data Availability:
  All data supporting the findings of this study are included in this article and its supplementary materials.
• How to cite:
  Lima, M. C. S., Romualdo, V. B., Costa, W. R. P., Gonçalves, R. L. N., Costa, A. C. A., Oliveira, L. R. C., Nóbrega, K. C., Farias, M. C. S., Nascimento, R. C. A. M., & Amorim, L. V. (2026). Polymer-based fluids for well workover: a comprehensive review. Polímeros: Ciência e Tecnologia, 36(3), e20260029. https://doi.org/10.1590/0104-1428.20250094

9. References

• ¹ Chiriac, A. (2014). Reservoir drill-in fluids, completion and workover fluids (Master’s thesis). Aalborg University Esbjerg, School of Engineering and Science (SES), Esbjerg, Denmark.
• ² Guo, B., Liu, X., & Tan, X. (Eds.) (2017). Well workover. In B. Guo, X. Liu, & X. Tan (Eds.), Petroleum production engineering Gulf Professional Publishing.
• ³ Bissoli, D. C., Chaves, G. L. D., & Ribeiro, G. M. (2016). Drivers to the workover rig problem. Journal of Petroleum Science Engineering, 139(1), 13-22. https://doi.org/10.1016/j.petrol.2015.12.009
  » https://doi.org/10.1016/j.petrol.2015.12.009
• ⁴ Lei, Q., Li, Y., Li, T., Li, H., Guan, B., Bi, G., Wang, J., Weng, D., Huang, S., & Han, W. (2020). Technical status and development direction of workover operation of PetroChina. Petroleum Exploration and Development, 47(1), 161-170. https://doi.org/10.1016/S1876-3804(20)60015-5
  » https://doi.org/10.1016/S1876-3804(20)60015-5
• ⁵ Mansour, H., Ahmad, M. M., & Dhafr, N. (2012). An investigation into benchmarking of workover activities of rigs in the oilfields. In Proceedings of the 20th International Conference on Flexible Automation and Intelligent Manufacturing Helsinki, Finland.
• ⁶ Aloise, D. J., Aloise, D., Rocha, C. T. M., Ribeiro, C. C., Ribeiro Filho, J. C., & Moura, L. S. S. (2006). Scheduling workover rigs for onshore oil production. Discrete Applied Mathematics, 154(5), 695-702. https://doi.org/10.1016/j.dam.2004.09.021
  » https://doi.org/10.1016/j.dam.2004.09.021
• ⁷ Diller, C. (2010). Field/well integrity issues, well abandonment planning and workover operations on an inadequately abandoned well: peace River Alberta case study. In Abu Dhabi International Petroleum Exhibition and Conference Abu Dhabi, United Arab Emirates. https://doi.org/10.2118/138287-MS
  » https://doi.org/10.2118/138287-MS
• ⁸ Mansour, H., & Ahmad, M. M. (2013). Framework for evaluation and improvement of workover rigs in oilfields. American Journal of Engineering Research, 4(4), 6-13. Retrieved in 2025, September 15, from https://www.ajer.org/papers/v4(04)/B04406013.pdf
  » https://www.ajer.org/papers/v4(04)/B04406013.pdf
• ⁹ Tomlins, A., Conrad, J., & Bocaneala, B. (2019). The world’s first offshore multilateral well completed with multistage proppant fracturing: a case study from offshore Black Sea. In SPE Hydraulic Fracturing Technology Conference, Woodlands, Texas, USA. https://doi.org/10.2118/194324-MS
  » https://doi.org/10.2118/194324-MS
• ¹⁰ Rae, P., Di Lullo, G., & Ahmad, A. B. (2002). Eliminating environmental risks in well construction and workover. In SPE Asia Pacific Oil and Gas Conference and Exhibition Melbourne, Australia. https://doi.org/10.2118/77812-MS
  » https://doi.org/10.2118/77812-MS
• ¹¹ Riley, S. M., Potter, G. F., Holmes, J. M., Jr., & Reeves, H. C., 3rd. (1984, September 16). Controlling incompatibilities of formation and kill‑weight fluids during workover. In 59th Annual Conference and Exhibition, Houston, Texas, USA. https://doi.org/10.2118/13131-MS
  » https://doi.org/10.2118/13131-MS
• ¹² MI SWACO (2013). Basic mud school presentation manual (pp. 1-13). Houston: MI SWACO.
• ¹³ Mardashov, D. V., Rogachev, M. K., Zeigman, Y. V., & Mukhametshin, V. V. (2021). Well killing technology before workover operation in complicated conditions. Energies, 14(3), 654. https://doi.org/10.3390/en14030654
  » https://doi.org/10.3390/en14030654
• ¹⁴ MI SWACO (2012). Completion fluids manual (pp. 5-12). Houston: MI SWACO.
• ¹⁵ Costa, W. R. P., Nóbrega, K. C., Costa, A. C. A., Nascimento, R. C. A. M., Souza, E. A., Oliveira, T. A., Barros, M., & Amorim, L. V. (2024). A liquid well barrier element for temporary plug and abandonment operations: a breakthrough approach. Processes (Basel, Switzerland), 12(10), 2190. https://doi.org/10.3390/pr12102190
  » https://doi.org/10.3390/pr12102190
• ¹⁶ Farias, M. C. S., Costa, W. R. P., Nóbrega, K. C., Romualdo, V. B., Costa, A. C. A., Nascimento, R. C. A. M., & Amorim, L. V. (2025). Thermal Degradation of Carboxymethyl Cellulose (CMC) in Saline Solution for Applications in Petroleum Industry Fluids. Polymers, 17(15), 2085. https://doi.org/10.3390/polym17152085 PMid:40808132.
  » https://doi.org/10.3390/polym17152085
• ¹⁷ Gonçalves, R. L. N., Costa, A. C. A., Lima, M. C. S., Nóbrega, K. C., Costa, W. R. P., Oliveira, L. R. C., Nascimento, R. C. A. M., Barros, M., Oliveira, T. A., & Amorim, L. V. (2025). A new application for salted water-based fluids with palygorskite: formulation designing for temporary plug and abandonment operations of petroleum wells. Applied Sciences (Basel, Switzerland), 15(6), 2980. https://doi.org/10.3390/app15062980
  » https://doi.org/10.3390/app15062980
• ¹⁸ Liu, X., Yuan, Z., Wang, A., Wang, C., Qu, J., Chen, B., Wei, B., Kapu, N. S., & Wen, Y. (2020). Cellulose nanofibril‑polymer hybrids for protecting drilling fluid at high salinity and high temperature. Carbohydrate Polymers, 229, 115465. https://doi.org/10.1016/j.carbpol.2019.115465 PMid:31826464.
  » https://doi.org/10.1016/j.carbpol.2019.115465
• ¹⁹ Beltrao, R. L. C., Sombra, C. L., Lage, A. C. V. M., Netto, J. R. F., & Henriques, C. C. D. (2009). SS: pre-salt Santos basin - Challenges and new technologies for the development of the pre-salt cluster, Santos Basin, Brazil. In Offshore Technology Conference Houston, TX, USA. https://doi.org/10.4043/19880-MS
  » https://doi.org/10.4043/19880-MS
• ²⁰ Gessner, T. R., & Barbosa, J. R., Jr. (2022). An internally consistent procedure to characterize single‑carbon‑number fractions for phase equilibrium of petroleum mixtures: application to Brazilian pre‑salt reservoir fluids. Journal of Petroleum Science and Engineering, 208(Pt E), 109723. https://doi.org/10.1016/j.petrol.2021.109723
  » https://doi.org/10.1016/j.petrol.2021.109723
• ²¹ Thomas, D. C. (1982). Thermal stability of starch- and carboxymethyl cellulose-based polymers used in drilling fluids. Society of Petroleum Engineers Journal, 22(2), 171-180. https://doi.org/10.2118/8463-PA
  » https://doi.org/10.2118/8463-PA
• ²² Eaton, B. A., & Smithey, M. (1971). Formation damage from workover and completion fluids. In SPE California Regional Meeting California, USA. https://doi.org/10.2118/3707-MS
  » https://doi.org/10.2118/3707-MS
• ²³ Lipton, D., & Burnett, D. B. (1976). Comparisons of polymers used in workover and completion fluids. In SPE California Regional Meeting California, USA. https://doi.org/10.2118/5872-MS
  » https://doi.org/10.2118/5872-MS
• ²⁴ Vollmer, D. P., & Alleman, D. J. (2001). HEC no longer the preferred polymer. In SPE International Symposium on Oilfield Chemistry Houston, TX, USA. https://doi.org/10.2118/65398-MS
  » https://doi.org/10.2118/65398-MS
• ²⁵ Yang, Y., Li, Y., Yao, J., Zhang, K., Iglauer, S., Luquot, L., & Wang, Z. (2019). Formation damage evaluation of a sandstone reservoir via pore-scale X-ray computed tomography analysis. Journal of Petroleum Science Engineering, 183, 106356. https://doi.org/10.1016/j.petrol.2019.106356
  » https://doi.org/10.1016/j.petrol.2019.106356
• ²⁶ Scheuerman, R. F. (1983). Guidelines for using HEC polymers for viscosifying solids-free completion and workover brines. Journal of Petroleum Technology, 35(2), 306-314. https://doi.org/10.2118/10666-PA
  » https://doi.org/10.2118/10666-PA
• ²⁷ Ezzat, A. M., Rosser, H. R., & Al-Humam, A. A. (1997). Control of microbiological activity in biopolymer-based drilling muds. In SPE/IADC Middle East Drilling Technology Conference Bahrain. https://doi.org/10.2118/39285-MS
  » https://doi.org/10.2118/39285-MS
• ²⁸ Li, B., Luo, P., Zhao, X., & Chen, L. (2024). Research and application of completion and workover fluid technology in heavy oil reservoir in Ecuador. In International Petroleum Technology Conference Dhahran, Saudi Arabia. https://doi.org/10.2523/IPTC-24160-MS
  » https://doi.org/10.2523/IPTC-24160-MS
• ²⁹ Lima, M. C. S., Romualdo, V. B., Oliveira, G. V. B., Silva Filho, E. D., Nóbrega, K. C., Costa, A. C. A., Souza, E. A., Camargo, S. T., Jr., Rodrigues, M. A. F., & Amorim, L. V. (2025). Assessment of formation damage in carbonate rocks: isolated contribution of filtration control agents in aqueous fluids. Applied Sciences (Basel, Switzerland), 15(21), 11572. https://doi.org/10.3390/app152111572
  » https://doi.org/10.3390/app152111572
• ³⁰ Rocha, L. A. S., & Azevedo, C. T. (2019). Projetos de poços de petróleo: geopressões e assentamento de colunas de revestimentos Rio de Janeiro: Editora Interciência.
• ³¹ Petri, D. F. S. (2015). Xanthan gum: a versatile biopolymer for biomedical and technological applications. Journal of Applied Polymer Science, 132(23), 42035. https://doi.org/10.1002/app.42035
  » https://doi.org/10.1002/app.42035
• ³² McNeilly, K., El-Sayed, M. A., Al-Blooshi, J., & Al-Qubaisi, S. (2017). ADMA rigless intervention campaign: Breathing new life in to old wells. In Abu Dhabi International Petroleum Exhibition & Conference Abu Dhabi, United Arab Emirates. https://doi.org/10.2118/188609-MS
  » https://doi.org/10.2118/188609-MS
• ³³ Siddig, O., Mahmoud, A. A., & Elkatatny, S. A. (2020). A review of different approaches for water-based drilling fluid filter cake removal. Journal of Petroleum Science Engineering, 192, 107346. https://doi.org/10.1016/j.petrol.2020.107346
  » https://doi.org/10.1016/j.petrol.2020.107346
• ³⁴ Vrålstad, T., Saasen, A., Fjær, E., Øia, T., Ytrehus, J. D., & Khalifeh, M. (2019). Plug & abandonment of offshore wells: ensuring long-term well integrity and cost-efficiency. Journal of Petroleum Science Engineering, 173, 478-491. https://doi.org/10.1016/j.petrol.2018.10.049
  » https://doi.org/10.1016/j.petrol.2018.10.049
• ³⁵ Nguyen, T. C., Miska, S., Saasen, A., & Maxey, J. (2014). Using Taguchi and ANOVA methods to study the combined effects of drilling parameters on dynamic barite sag. Journal of Petroleum Science Engineering, 121, 126-133. https://doi.org/10.1016/j.petrol.2014.06.029
  » https://doi.org/10.1016/j.petrol.2014.06.029
• ³⁶ Lippmann, F. (1973). Sedimentary carbonate minerals USA: Springer-Verlag Berlin. https://doi.org/10.1007/978-3-642-65474-9
  » https://doi.org/10.1007/978-3-642-65474-9
• ³⁷ Talukdar, P., & Gogoi, S. B. (2015). Use of calcium carbonate as bridging and weighting agent in the non-damaging drilling fluid for some oilfields of Upper Assam Basin. International Journal of Current Research, 7(8), 18964-18981. Retrieved in 2025, September 15, from https://www.journalcra.com/sites/default/files/issue-pdf/9945.pdf
  » https://www.journalcra.com/sites/default/files/issue-pdf/9945.pdf
• ³⁸ Nguyen, T., Silva, C., Dare, A., Saasen, A., & AlSafran, E. (2016). Optimization of calcium carbonate particles and pH in oil based drilling fluids to minimize barite sag. In AADE Fluids Technical Conference and Exhibition Houston, TX, USA. Retrieved in 2025, September 15, from https://www.aade.org/application/files/1815/7131/8493/AADE-16-FTCE-22_-_Nguyen.pdf
  » https://www.aade.org/application/files/1815/7131/8493/AADE-16-FTCE-22_-_Nguyen.pdf
• ³⁹ Hopkins, S. D., Gogovi, G. K., Weisel, E. W., Handler, R. A., & Blaisten-Barojas, E. (2020). Polyacrylamide in glycerol solutions from an atomistic perspective of the energetics, structure, and dynamics. AIP Advances, 10(8), 085011. https://doi.org/10.1063/5.0020850
  » https://doi.org/10.1063/5.0020850
• ⁴⁰ Câmara, P. C. F., Morais, S. C., Marques, N. N., Souza, E. A., Gasparotto, L. H. S., & Balaban, R. C. (2023). Polyacrylamide and poly-ethylenimine mixed hydrogels tailored with crude glycerol for conformance fluids: gelation performance and thermal stability. Fuel, 354, 129376. https://doi.org/10.1016/j.fuel.2023.129376
  » https://doi.org/10.1016/j.fuel.2023.129376
• ⁴¹ Caenn, R., Darley, H. C. H., & Gray, G. R. (2011). Composition and properties of drilling and completion fluids Waltham: Gulf Professional Publishing.
• ⁴² Kalantariasl, A., Zeinijahromi, A., & Bedrikovetsky, P. (2014). External filter cake buildup in dynamic filtration: mechanisms and key factors. In SPE International Symposium and Exhibition on Formation Damage Control Lafayette, LA, USA https://doi.org/10.2118/168144-MS
  » https://doi.org/10.2118/168144-MS
• ⁴³ Ezell, R. G., Ezzat, A. M., Turner, J. K., & Wu, J. J. (2010, 10-12 de fevereiro). New filtration-control polymer for improved brine-based reservoir drilling-fluids performance at temperatures in excess of 400°F and high pressure. In SPE International Symposium and Exhibition on Formation Damage Control Lafayette, Louisiana, USA. https://doi.org/10.2118/128119-MS
  » https://doi.org/10.2118/128119-MS
• ⁴⁴ Crumpton, H. (2018). Well control for completions and interventions Waltham: Gulf Professional Publishing.
• ⁴⁵ Ahamed, S. B., & Belhadri, M. (2009). Rheological properties of biopolymers drilling fluids. Journal of Petroleum Science Engineering, 67(3-4), 84-90. https://doi.org/10.1016/j.petrol.2009.04.001
  » https://doi.org/10.1016/j.petrol.2009.04.001
• ⁴⁶ Luz, R. C. S., Fagundes, F. P., & Balaban, R. B. (2017). Water-based drilling fluids: the contribution of xanthan gum and carboxymethylcellulose on filtration control. Chemical Papers, 71(12), 2365-2373. https://doi.org/10.1007/s11696-017-0231-7
  » https://doi.org/10.1007/s11696-017-0231-7
• ⁴⁷ Nwosu, O. U., & Ewulonu, C. M. (2014). Rheological behaviour of eco-friendly drilling fluids from biopolymers. Journal of Polymer & Biopolymer Physics & Chemistry, 2(3), 50-54. http://doi.org/10.12691/jpbpc-2-3-2
  » http://doi.org/10.12691/jpbpc-2-3-2
• ⁴⁸ Hodge, R. M. (1998). HEC precipitation at elevated temperature: an unexpected source of formation damage. SPE Drilling & Completion, 13(2), 88-91. https://doi.org/10.2118/38155-PA
  » https://doi.org/10.2118/38155-PA
• ⁴⁹ Huang, X., Lv, K., Sun, J., Lu, Z., Bai, Y., Shen, H., & Wang, J. (2019). Enhancement of thermal stability of drilling fluid using laponite nanoparticles under extreme temperature conditions. Materials Letters, 248, 146-149. https://doi.org/10.1016/j.matlet.2019.04.005
  » https://doi.org/10.1016/j.matlet.2019.04.005
• ⁵⁰ Shaheed, L. H. (2022). Analysis and mitigation of high-pressure and high-temperature well completion design of Elkin/Franklin Fields in the North Sea. Journal of Petroleum Research and Studies, 12(1 Suppl), 1-17. https://doi.org/10.52716/jprs.v12i1(Suppl.).617
  » https://doi.org/10.52716/jprs.v12i1(Suppl.).617
• ⁵¹ Sauman, M., Law, B., French, C. P., & Pianca, J. (2000). Enviromental protection in drilling operation using minimum pit and zero cost. In IADC/SPE Asia Pacific Drilling Technology Conference and Exhibition Kuala Lumpur, Malaysia. https://doi.org/10.2118/62765-MS
  » https://doi.org/10.2118/62765-MS
• ⁵² Luheng, Q. (2014). The application of polymer mud system in drilling engineering. Procedia Engineering, 73, 230-236. https://doi.org/10.1016/j.proeng.2014.06.192
  » https://doi.org/10.1016/j.proeng.2014.06.192
• ⁵³ Singh, B., & Sharma, N. (2008). Mechanistic implications of plastic degradation. Polymer Degradation & Stability, 93(3), 561-584. https://doi.org/10.1016/j.polymdegradstab.2007.11.008
  » https://doi.org/10.1016/j.polymdegradstab.2007.11.008
• ⁵⁴ Carico, R. D., & Bagshaw, F. R. (1978). Description and use of polymers used in drilling, workovers, and completions. In SPE Production Technology Symposium Lubbock, TX, USA. https://doi.org/10.2118/7747-MS
  » https://doi.org/10.2118/7747-MS
• ⁵⁵ Wang, S., Chen, F., Guo, J., Li, Y., Zhao, F., & Zhou, S. (2019). Adsorption damage of hydroxypropyl guar gum to porous media composed of quartz. Journal of Petroleum Science Engineering, 182, 106379. https://doi.org/10.1016/j.petrol.2019.106379
  » https://doi.org/10.1016/j.petrol.2019.106379
• ⁵⁶ Elkatatny, S., Mahmoud, M., & Abdelgawad, K. (2018). Reaction of chelating agents with guar gum polymer for completion fluid. Arabian Journal for Science and Engineering, 43(11), 6481-6491. https://doi.org/10.1007/s13369-018-3278-z
  » https://doi.org/10.1007/s13369-018-3278-z
• ⁵⁷ Bahamdan, A., & Daly, W. H. (2006). Poly(oxyalkylene) grafts to guar gum with applications in hydraulic fracturing fluids. Polymers for Advanced Technologies, 17(9–10), 679-681. https://doi.org/10.1002/pat.814
  » https://doi.org/10.1002/pat.814
• ⁵⁸ Cao, X., Shi, Y., Li, W., Zeng, P., Zheng, Z., Feng, Y., & Yin, H. (2021). Comparative studies on hydraulic fracturing fluids for high-temperature and high-salt oil reservoirs: synthetic polymer versus guar gum. ACS Omega, 6(39), 25421-25429. https://doi.org/10.1021/acsomega.1c03394 PMid:34632200.
  » https://doi.org/10.1021/acsomega.1c03394
• ⁵⁹ Dajun, G. (2021). Study on instant low friction seawater based guar gum fracturing fluids. Drilling Fluid & Completion Fluid, 38(3), 371-374.
• ⁶⁰ Wang, J., Huang, Y., Zhang, Y., Zhou, F., Yao, E., & Wang, E. (2020). Study of fracturing fluid on gel breaking performance and damage to fracture conductivity. Journal of Petroleum Science Engineering, 193, 107443. https://doi.org/10.1016/j.petrol.2020.107443
  » https://doi.org/10.1016/j.petrol.2020.107443
• ⁶¹ Akpan, E. U., Enyi, G. C., & Nasr, G. G. (2020). Enhancing the performance of xanthan gum in water-based mud systems using an environmentally friendly biopolymer. Journal of Petroleum Exploration and Production Technology, 10(5), 1933-1948. https://doi.org/10.1007/s13202-020-00837-0
  » https://doi.org/10.1007/s13202-020-00837-0
• ⁶² Wu, L., Xu, T., Han, X., & Pan, X. (2011). Research on high temperature stability effects of xanthan gum. Zuanjing Ye yu Wanjing Ye- Drilling Fluid & Completion Fluid,28(6), 77-80.
• ⁶³ Zhu, W., & Zheng, X. (2021). Effective modified xanthan gum fluid loss agent for high-temperature water-based drilling fluid and the filtration control mechanism. ACS Omega, 6(37), 23788-23801. https://doi.org/10.1021/acsomega.1c02617 PMid:34568659.
  » https://doi.org/10.1021/acsomega.1c02617
• ⁶⁴ Dolz, M., Jiménez, J., Hernández, M. J., Delegido, J., & Casanovas, A. (2007). Flow and thixotropy of non-contaminating oil drilling fluids formulated with bentonite and sodium carboxymethyl cellulose. Journal of Petroleum Science Engineering, 57(3-4), 294-302. https://doi.org/10.1016/j.petrol.2006.10.008
  » https://doi.org/10.1016/j.petrol.2006.10.008
• ⁶⁵ Menezes, R. R., Marques, L. N., Campos, L. A., Ferreira, H. S., Santana, L. N. L., & Neves, G. A. (2010). Use of statistical design to study the influence of CMC on the rheological properties of bentonite dispersions for water-based drilling fluids. Applied Clay Science, 49(1-2), 13-20. https://doi.org/10.1016/j.clay.2010.03.013
  » https://doi.org/10.1016/j.clay.2010.03.013
• ⁶⁶ Srungavarapu, M., Patidar, K. K., Pathak, A. K., & Mandal, A. (2018). Performance studies of water-based drilling fluid for drilling through hydrate bearing sediments. Applied Clay Science, 152, 211-220. https://doi.org/10.1016/j.clay.2017.11.014
  » https://doi.org/10.1016/j.clay.2017.11.014
• ⁶⁷ Kuma, M., Das, B. M., & Talukdar, P. (2020). The effect of salts and hematite on carboxymethyl cellulose–bentonite and partially hydrolyzed polyacrylamide–bentonite muds for an effective drilling in shale formations. Journal of Petroleum Exploration and Production Technology, 10(2), 395-405. https://doi.org/10.1007/s13202-019-0722-x
  » https://doi.org/10.1007/s13202-019-0722-x
• ⁶⁸ Teymoori, R. N., & Alaskarin, M. K. (2007). Effects of salinity, pH and temperature on CMC polymer and XC polymer performance. International Journal of Engineering, 20(3), 283-290. Retrieved in 2025, September 15, from https://www.ije.ir/article_71677.html
  » https://www.ije.ir/article_71677.html
• ⁶⁹ Carico, R. D. (1976). Suspension properties of polymer fluids used in drilling, workover, and completion operations. In SPE California Regional Meeting California, USA. https://doi.org/10.2118/5870-MS
  » https://doi.org/10.2118/5870-MS
• ⁷⁰ Elemam, A. E., Hussien, R. A. M., Ibrahim, A. A., & Mohamed, S. A. (2015). Impacts of polyanionic cellulose polymer (PAC-LV) on drilling fluids properties. SUST Journal of Engineering and Computer Science, 16(3), 30-36. Retrieved in 2025, September 15, from https://repository.sustech.edu/handle/123456789/16631
  » https://repository.sustech.edu/handle/123456789/16631
• ⁷¹ Jia, X., Zhao, X., Chen, B., Egwu, S. B., & Huang, Z. (2022). Polyanionic cellulose/hydrophilic monomer copolymer grafted silica nanocomposites as HTHP drilling fluid-loss control agent for water-based drilling fluids. Applied Surface Science, 578, 152006. https://doi.org/10.1016/j.apsusc.2021.152089
  » https://doi.org/10.1016/j.apsusc.2021.152089
• ⁷² Liu, Z., Zhang, C., Li, Q., Davarpanah, A., & Metwally, A. S. M. (2022). Effectiveness of cellulose polyanionic-based polymers on the measurement of rheological properties of water-based drilling fluids in high-pressure high-temperature fractured shale reservoirs. Applied Water Science, 12(5), 85. https://doi.org/10.1007/s13201-022-01595-6
  » https://doi.org/10.1007/s13201-022-01595-6
• ⁷³ Kafashi, S., Rasaei, M., & Karim, G. (2017). Effects of sugarcane and polyanionic cellulose on rheological properties of drilling mud: an experimental approach. Egyptian Journal of Petroleum, 26(2), 371-374. https://doi.org/10.1016/j.ejpe.2016.05.009
  » https://doi.org/10.1016/j.ejpe.2016.05.009
• ⁷⁴ Fang, Q., Zhao, X., Sun, H., Wang, Z., Qiu, Z., Shan, K., & Ren, X. (2022). Formation-damage mechanism and gel-breaker-free drill-in fluid for carbonate reservoir. Gels (Basel, Switzerland), 8(9), 565. https://doi.org/10.3390/gels8090565 PMid:36135276.
  » https://doi.org/10.3390/gels8090565
• ⁷⁵ Audibert, A., Argillier, J.-F., Ladva, H. K. J., Way, P. W., & Hove, A. O. (1999). Role of polymers on formation damage. In SPE European Formation Damage Conference The Hague, Netherlands. https://doi.org/10.2118/54767-MS
  » https://doi.org/10.2118/54767-MS
• ⁷⁶ Mahmoud, H., Alhajabdalla, M., Nasser, M. S., Hussein, I. A., Ahmed, R., & Karami, H. (2021). Settling behavior of fine cuttings in fiber-containing polyanionic fluids for drilling and hole cleaning application. Journal of Petroleum Science Engineering, 199, 108377. https://doi.org/10.1016/j.petrol.2020.108337
  » https://doi.org/10.1016/j.petrol.2020.108337
• ⁷⁷ Mohamed, A., Salehi, S., & Ahmed, R. (2021). Rheological properties of drilling fluids containing special additives for geothermal drilling applications. In 46th Workshop on Geothermal Reservoir Engineering Stanford, California, USA: Stanford University.
• ⁷⁸ Al-Humam, A. A., Ezzat, A. M., Ba Hamdan, A. A., Sindi, M. E., Al-Humaid, G. A., & Zhu, X. (2021). Drilling fluids microbial impact and mitigation. Journal of Physical Science and Application, 11(1), 22-28. https://doi.org/10.17265/2159-5348/2021.01.004
  » https://doi.org/10.17265/2159-5348/2021.01.004
• ⁷⁹ Anderson, Z., Ioannou, A., Howard, S., & Downs, J. (2023). Understanding and managing the natural self-breaking behaviour of xanthan in reservoir drill-in, completion and workover fluids. In SPE International Conference on Oilfield Chemistry The Woodlands, TX, USA. https://doi.org/10.2118/213822-MS
  » https://doi.org/10.2118/213822-MS
• ⁸⁰ Fink, J. K. (2012). Petroleum engineer’s guide to oil field chemicals and fluids Waltham: Gulf Professional Publishing.
• ⁸¹ Abdiyev, K., Marić, M., Orynbaev, B., Zhursumbaeva, M., Seitkaliyeva, N., & Toktarbay, Z. (2023). A novel cationic polymer surfactant for regulation of the rheological and biocidal properties of the water-based drilling muds. Polymers, 15(2), 330. https://doi.org/10.3390/polym15020330 PMid:36679210.
  » https://doi.org/10.3390/polym15020330
• ⁸² Quan, H., Li, H., Huang, Z., Zhang, T., & Da, S. (2014). Copolymer SJ-1 as a fluid loss additive for drilling fluid with high content of salt and calcium. International Journal of Polymer Science, 2014(1), 201301. https://doi.org/10.1155/2014/201301
  » https://doi.org/10.1155/2014/201301
• ⁸³ Xie, B., Zhang, X., Li, Y., Liu, W., & Luo, M. (2019). Application of a novel thermo-sensitive copolymer as a potential rheological modifier for deepwater water-based drilling fluids. Colloids and Surfaces. A, Physicochemical and Engineering Aspects, 581, 123848. https://doi.org/10.1016/j.colsurfa.2019.123848
  » https://doi.org/10.1016/j.colsurfa.2019.123848
• ⁸⁴ Inam, W., Bhadane, R., Akpolat, R. N., Taiseer, R. A., Filippov, S. K., Salo-Ahen, O. M. H., Rosenholm, J. M., & Zhang, H. (2022). Interactions between polymeric nanoparticles and different buffers as investigated by zeta potential measurements and molecular dynamics simulations. VIEW, 3(4), 20210009. https://doi.org/10.1002/VIW.20210009
  » https://doi.org/10.1002/VIW.20210009
• ⁸⁵ Li, M., Gu, S., Jin, J., Zheng, Y., & Xie, D. (2020). Research on the influence of polyanionic cellulose on the microstructure and properties of oil well cement. Construction & Building Materials, 259, 119841. https://doi.org/10.1016/j.conbuildmat.2020.119841
  » https://doi.org/10.1016/j.conbuildmat.2020.119841
• ⁸⁶ Cai, J., Yu, B., Zou, M., & Mei, M. (2010). Fractal analysis of invasion depth of extraneous fluids in porous media. Chemical Engineering Science, 65(18), 5178-5186. https://doi.org/10.1016/j.ces.2010.06.013
  » https://doi.org/10.1016/j.ces.2010.06.013
• ⁸⁷ Kok, M. V., & Iscan, G. (2009). Effect of carboxymethyl cellulose and determination of pore throat criteria for water-based drilling fluids. Energy Sources. Part A, Recovery, Utilization, and Environmental Effects, 31(5), 396-405. https://doi.org/10.1080/15567030801907254
  » https://doi.org/10.1080/15567030801907254
• ⁸⁸ Zang, J., & Chen, X. (2018). Formation damage by thermal methods applied to heavy oil reservoirs. In B. Yuan, & D. A. Wood (Eds.), Formation damage during improved oil recovery: fundamentals and applications (pp. 361-384). USA: Elsevier. https://doi.org/10.1016/B978-0-12-813782-6.00009-9
  » https://doi.org/10.1016/B978-0-12-813782-6.00009-9
• ⁸⁹ Mahmoud, O., & Nasr-El-Din, H. A. (2021). Formation-damage assessment and filter-cake characterization of Ca-bentonite fluids enhanced with nanoparticles. SPE Drilling & Completion, 36(1), 75-87. https://doi.org/10.2118/191155-PA
  » https://doi.org/10.2118/191155-PA
• ⁹⁰ Al Jaberi, J., Bageri, B. S., Adebayo, A. R., Patil, S., Barri, A., & Salin, R. B. (2021). Evaluation of formation damages during filter cake deposition and removal process: the effect of primary damage on secondary damage. Petroleum Science, 18(4), 1153-1162. https://doi.org/10.1016/j.petsci.2021.07.004
  » https://doi.org/10.1016/j.petsci.2021.07.004
• ⁹¹ Ezell, R., & Harrison, D. J. (2008). Design of improved high-density, thermally-stable drill-in fluid for HTHP applications. In SPE Annual Technical Conference and Exhibition. Denver, CO, USA. https://doi.org/10.2118/115537-MS
  » https://doi.org/10.2118/115537-MS
• ⁹² Patel, M. C., & Singh, A. (2016). Near wellbore damage and types of skin depending on mechanism of damage. In SPE International Conference and Exhibition on Formation Damage Control Lafayette, LA, USA. https://doi.org/10.2118/179011-MS
  » https://doi.org/10.2118/179011-MS
• ⁹³ Quintero, L., Newberry, M., Morales, R., & Davis, C. (2017). Organic and inorganic formation damage removal using customized formulations. In SPE Western Regional Meeting Bakersfield, CA, USA. https://doi.org/10.2118/185735-MS
  » https://doi.org/10.2118/185735-MS
• ⁹⁴ Li, Z., Zhang, W., Tang, Y., Li, B., Song, Z., & Hou, J. (2016). Formation damage during alkaline-surfactant-polymer flooding in the Sanan-5 block of the Daqing Oilfield, China. Journal of Natural Gas Science and Engineering, 35(Pt A), 826-835. https://doi.org/10.1016/j.jngse.2016.07.046
  » https://doi.org/10.1016/j.jngse.2016.07.046
• ⁹⁵ Mohammadi, M. K., Riahi, S., & Boek, E. S. (2023). An insight review on formation damage induced by drilling fluids. Reviews in Chemical Engineering, 39(3), 387-415. https://doi.org/10.1515/revce-2020-0106
  » https://doi.org/10.1515/revce-2020-0106
• ⁹⁶ Rahmati, M., Khosravi, M., Tanha, A. A., & Rafiq Albajalan, A. (2024). Evaluation of formation damage and filter cake removal with a new LPM drilling fluid additive. Results in Engineering, 23, 102656. https://doi.org/10.1016/j.rineng.2024.102656
  » https://doi.org/10.1016/j.rineng.2024.102656

Edited by

• Editor-in-Chief:
  Sebastião V. Canevarolo

Data availability

All data supporting the findings of this study are included in this article and its supplementary materials.

Publication Dates

• Publication in this collection
  24 July 2026
• Date of issue
  2026

History

• Received
  29 Sept 2025
• Reviewed
  06 May 2026
• Accepted
  13 May 2026