Synthesis of a zwitterionic quaternary ammonium polymer and its application in fluid loss control for water-based drilling fluid

Tao Peng; Peng Xu; Lei Pu; Jing Li; Bangzhe Wang; Jingwei Liu

doi:10.25259/AJC_485_2025

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Original Article

:19;

4852025

doi:

10.25259/AJC_485_2025

Synthesis of a zwitterionic quaternary ammonium polymer and its application in fluid loss control for water-based drilling fluid

Tao Peng^a,, Peng Xu^b,*, Lei Pu^a, Jing Li^c, Bangzhe Wang^a, Jingwei Liu^a

aCooperative Innovation Center of Unconventional Oil and Gas, Yangtze University (Ministry of Education & Hubei Province), Wuhan, Hubei, China

bHubei Key Laboratory of Oil and Gas Drilling and Production Engineering, Yangtze University, Wuhan, China

cNational Engineering Research Center for Oil & Gas Drilling and Completion Technology, School of Petroleum Engineering, Yangtze University, Wuhan, China

*Corresponding author: E-mail address: cdxupeng@yangtzeu.edu.cn (P. Xu)

Received: 2025-05-09, Accepted: 2025-10-04, Epub ahead of print: 2026-02-04, Published: 2026-03-02

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Abstract

With the continuous progress of exploration and development of deep and ultra-deep oil and gas reservoirs in China, high temperature and high salinity environments pose substantial challenges to the effectiveness of drilling fluids. A high-temperature and salt-resistant zwitterionic polymer fluid loss additive (HTS-COFL) was synthesized. By introducing specific functional groups into the molecular chain, the stability and fluid loss reduction performance of this additive in high temperature and high salinity environments have been enhanced. HTS-COFL is prepared from acrylamide (AM), 2-acrylamido-2-methylpropanesulfonic acid (AMPS), dimethyldiallylammonium chloride (DMDAAC), and N-acryloylmorpholine (ACMO) as monomers through free radical polymerization in aqueous solution. The molecular structure and thermal resistance of the polymer were evaluated using Fourier transform infrared (FTIR), thermogravimetric analysis (TGA), and nuclear magnetic resonance (NMR) techniques. Additionally, its rheological and fluid loss properties were tested under different temperatures, salt concentrations, and calcium ion environments. The results indicate that the drilling fluid with HTS-COFL added exhibits excellent high temperature and high salinity resistance. The outstanding performance of HTS-COFL is mainly attributed to the synergistic effect of functional groups such as sulfonic acid, quaternary ammonium salt, and morpholine ring. These groups not only enhance the rigidity and steric hindrance of the polymer chain but also improve its adsorption capacity for bentonite particles. This study offers scientific guidance for the development of fluid loss additives suitable for high-temperature and high-salinity reservoirs by exploring the introduction of functional groups and their synergistic effects. This is conducive to enhancing the efficiency and economic feasibility of water-based drilling fluids under complex downhole conditions and holds significant theoretical and practical value.

Keywords

Fluid loss additive

High-temperature and salt-resistant

Polymer

Water-based drilling fluids

Zwitterion

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1. Introduction

Drilling fluid plays a vital role in drilling processes and is commonly referred to as the “lifeblood of drilling” [1]. As China continues to promote deep and ultra-deep reservoir exploration and development, drilling fluids are playing an increasingly important role in oil and gas production [2-4].

The functions of drilling fluid include transporting cuttings, stabilizing the wellbore, cooling the drill bit, controlling formation pressure, assisting the drill bit in rock breaking, and preventing filtrate from invading the formation, etc [5-7]. Oil-based drilling fluid is widely used in high-temperature and high-pressure environments due to its good inhibition of shale expansion and high temperature stability. However, its high cost and potential environmental pollution problems have limited its application [8]. Compared to other types, water-based drilling fluids offer cost-effectiveness and greater environmental compatibility, contributing to their widespread adoption. Nevertheless, as formation temperatures increase, the high-temperature resistance of water-based drilling fluids faces significant challenges. High-temperature environments can cause drilling fluid additives to fail, and salt intrusion can further affect their performance [9,10]. Therefore, enhancing the high-temperature resistance of water-based drilling fluid additives has become a key focus of current research.

High-molecular-weight polymer fluid loss additives are an important component of water-based drilling fluids. It can minimize the infiltration of filtrate into the formation to the greatest extent, stabilize the wellbore, and ensure the regularity of the well diameter [11]. Water-based drilling fluid loss reducers are mainly high-molecular polymers, which can be classified into synthetic polymer types, biomass material modification types, and natural products and their modifications [12-14]. Natural polymer materials such as polysaccharides, gelatin, modified starch, and modified cellulose are widely used in low- to medium-temperature drilling because of their environmental protection and low cost. However, natural polymer fluid loss additives tend to fail at high temperatures and cannot effectively prevent filtrate intrusion. High temperature environments can lead to phenomena such as clay particle agglomeration, molecular chain curling, and thermal degradation, resulting in the failure of fluid loss reducers [15,16].

To solve this problem, researchers have conducted extensive studies on how to improve the temperature resistance of filter loss reducers. With the increasing maturity of high-temperature water-based drilling fluid technology, water-based drilling fluids have been successfully applied under high temperature conditions [17]. Researchers have enhanced the thermal and salt resistance of fluid loss additives by synthesizing functional polymers or modifying natural macromolecules. Currently, synthetic fluid loss reducers using 2-Acrylamido-2-methylpropane sulfonic acid (AMPS) as the primary monomer are widely applied. The presence of active groups such as carbon-carbon double bonds, sulfonic acid groups, and amide groups in its molecular structure enhances the functionality of the polymer [18]. Wang et al [19] synthesized two high-temperature-resistant polymers using AMPS and other monomers, demonstrating temperature resistance up to 220°C and salt resistance up to 5%. AMPS demonstrates excellent reactivity and compatibility in copolymer systems, making it suitable for integration with various monomers derived from synthetic polymers, natural macromolecules, and nanomaterials [19]. In high temperature and high salinity environments, the surface negative charge of clay decreases, leading to particle agglomeration and the destruction of its network structure. This negatively impacts its fluid loss reduction capability and shear-thinning properties [20,21]. Introducing specific functional groups, such as amino groups, quaternary ammonium salts, sulfonic acids, etc., into some synthetic polymer loss reducers can improve the temperature and salt resistance of the loss reducers. Li et al [21] synthesized a copolymer containing a cyclic side group that adsorbs efficiently on the bentonite surface. This reduces the zeta potential and particle size of bentonite adsorption, thus forming a low-permeability filter cake. In another study, Li et al [22] prepared an amphoteric hydrophobic associative copolymer featuring micro-crosslinking. This polymer enhances the hydration and dispersion of bentonite through hydrogen bonding and hydrophobic association, thereby improving the stability of drilling fluid under high temperature conditions. Additionally, quaternary ammonium compounds, such as diallyl dimethyl ammonium chloride (DMDAAC), interact with sulfonic anions to form stable heterocyclic intramolecular bonds within the polymer. This interaction can enhance the rigidity of the molecular chain and increase the steric hindrance of the molecular chain, thereby enhancing the polymer’s resistance to temperature and salt [23]. Another functional monomer, N-acryloyl morpholine (ACMO), features a hydrophilic morpholine group and a hydrophobic carbon chain structure. It can effectively inhibit the decomposition of the amide group at high temperature to improve the thermal stability of the polymer [24].

This study synthesized a high-temperature and salt-resistant fluid loss reduction agent (HTS-COFL) using AM, AMPS, DMDAAC, and ACMO as monomers. AM provides amide adsorption groups to enhance adsorption onto bentonite particles; AMPS contributes anionic sulfonic acid groups to improve high temperature and salt resistance; DMDAAC introduces cationic quaternary ammonium groups for enhanced hydrolytic stability; and ACMO offers morpholine ring groups to increase polymer rigidity and steric hindrance, thereby enhancing high temperature resistance [25]. By utilizing common and cost-effective polymer monomers for free radical polymerization, a high-temperature and salt-resistant fluid loss reducer was developed.

2. Materials and Methods

2.1. Materials

The polymer monomers used in this study include acrylamide (AM, analytical grade, 99%), 2-acrylamide-2-methylpropanesulfonic acid (AMPS,≥98%), diallyl dimethylammonium chloride (DMDAAC, 60% aqueous solution), and ACMO. Other chemical reagents such as sodium hydroxide (NaOH, analytical grade), ammonium persulfate (APS, analytical grade), sodium bisulfite (NaHSO₃, analytical grade), sodium chloride (NaCl), and calcium sulfate (CaSO₄), were all purchased from Shanghai Maclin Biochemical Co., LTD. The bentonite used in the experiment was provided by China Oilfield Services Limited (COSL), and the experimental water was deionized water self-made in the laboratory. Thermogravimetric analysis (TGA) was accomplished using the STA 2500 Regulus thermal analyzer produced by Netzsch of Germany. The characterization of the molecular structure was carried out by Fourier transform infrared spectroscopy (FTIR) and liquid nuclear magnetic resonance spectroscopy (NMR, Bruker 600 MHz, Germany). A Model 1103-12 rotational viscometer (Qingdao Chuangmeng Instrument Co., Ltd., China) was used to measure the viscosity parameters of the drilling fluid.

2.2. Synthesis of HTS-COFL

The temperature- and salt-resistant fluid loss additive HTS-COFL was synthesized via aqueous free-radical polymerization, as illustrated in Figure 1. Initially, 60 mL of deionized water was measured and transferred into a beaker placed on a magnetic stirrer. Subsequently, 7.46 g of AM was added and stirred until completely dissolved. Under continuous stirring, 3.2 g of AMPS was gradually introduced into the solution. The pH was then adjusted to 9.0-10.0 using an appropriate amount of sodium hydroxide (NaOH). Following pH adjustment, 3.2 g of DMDAAC and 2.13 g of ACMO were added to the mixture and stirred for an additional 3 min to ensure homogeneity. The pre-polymerization solution was subsequently transferred into a three-neck round-bottom flask, and the water bath temperature was set to 60°C. Stirring was maintained at 500 rpm throughout the reaction process. Once the system reached the designated temperature, a redox initiator system consisting of APS and sodium bisulfite (NaHSO₃) was introduced. Nitrogen gas was continuously purged into the flask to maintain an inert atmosphere. Polymerization proceeded until a transparent gel was formed (Figure 2), indicating the completion of the reaction. The resulting gel-like polymer was washed thoroughly with anhydrous ethanol to remove unreacted monomers and residual water. The purified product was then dried in a vacuum freeze dryer for 24 h. Finally, the dried polymer was ground into a fine white powder, yielding the fluid loss additive HTS-COFL, which was stored for subsequent characterization and performance evaluation.

2.3. Structural characterization of HTS-COFL

2.3.1. Fourier transform infrared analysis

The sample was processed into pellets for analysis. The FTIR spectrometer was calibrated, including zero-point, wavenumber, and background calibrations. The wavenumber range was set to 4000-400 cm^-1. The prepared sample was then placed in the FTIR spectrometer, and the instrument was started for data acquisition. The resulting spectrum and characteristic absorption peaks were analyzed.

2.3.2. Thermogravimetric analysis.

The sample was ground into a fine powder, and 20 mg of the sample was weighed. Before testing, the TGA instrument was calibrated using a standard material (calcium oxalate monohydrate). The heating rate was set to 20°C/min, with a temperature range from room temperature to 800°C, under a nitrogen atmosphere. The prepared sample was evenly distributed on the instrument’s sample tray. The sample was then heated, and its weight changes with temperature were recorded. The TG and derivative thermogravimetric (DTG) curves output by the instrument were analyzed to study the underlying mechanisms.

2.3.3 Proton nuclear magnetic resonance analysis

Approximately 10 mg of the sample was weighed into a 1.5 mL centrifuge tube, and 500 μL of deuterium oxide (D₂O) was added. While the sample was allowed to dissolve, the NMR instrument was calibrated. During the acquisition process, a short pulse of the magnetic field was applied to excite the hydrogen nuclei in the sample. Upon relaxation, the nuclei emitted signals at characteristic resonance frequencies. These signals were detected, converted into electronic data, and subsequently processed via Fourier transformation to yield the final ¹H NMR spectrum. The resulting spectrum was then interpreted in conjunction with the IR spectrum to further verify the molecular structure of the synthesized polymer.

2.4. Performance assessment of HTS-COFL drilling fluid

2.4.1. Preparation of drilling fluid

(1)

A volume of 400 mL of hot water was added to a high-speed mixing cup, and the stirring speed was set to 6000 rpm. While stirring, 12 g of bentonite, 0.6 g of sodium hydroxide, and 0.6 g of anhydrous sodium carbonate were sequentially added. During mixing, a glass rod was used to scrape any powder adhering to the cup walls back into the suspension. Stirring was continued for 2 h to ensure complete dispersion. Afterward, the mixture was covered with plastic wrap and allowed to stand undisturbed at room temperature for h to achieve full hydration. The resulting product was a pre-hydrated freshwater drilling fluid.
(2)

Evaluation of salt resistance: The fluid loss reducer HTS-COFL was added to the pre-hydrated freshwater drilling fluid, followed by the addition of 5%, 10%, 20%, and 30% sodium chloride, respectively. The performance of the drilling fluid was measured before aging. Subsequently, the samples were aged at 180°C for 16 h, and their rheological properties and fluid loss were remeasured. The mud cakes formed during the aging process were extracted, labeled, and dried for subsequent microscopic structure analysis.
(3)

Evaluation of calcium resistance: The fluid loss reducer HTS-COFL was added to the pre-hydrated freshwater drilling fluid, followed by the addition of 0.5%, 1%, 1.5%, and 2% calcium chloride, respectively. The performance of the drilling fluid was measured before aging. Subsequently, the samples were aged at 180°C for 16 h, and their rheological properties and fluid loss were remeasured. The mud cakes formed during the aging process were extracted, labeled, and dried for subsequent microscopic structure analysis.

2.4.2. Measurement of rheological properties.

Use a six-speed rotational viscometer (ZNN-D6 model, manufactured by Qingdao Chuangmeng Instrument Co., Ltd., China) to measure the relevant performance parameters of the drilling fluid. Before testing, stir the drilling fluid at a high speed of 6000 rpm for 5 min to ensure thorough mixing and uniformity. The rheological performance of the stirred sample is then tested at room temperature. The viscosity of drilling fluid at different shear rates is measured using a six-speed rotational viscometer to obtain other related parameters. Instrument readings were recorded at rotational speeds of 600, 300, 200, 100, 6, and 3 rpm. The values at 600 rpm (φ₆₀₀) and 300 rpm (φ₃₀₀) were used to calculate the apparent viscosity (AV), plastic viscosity (PV), and yield point (YP) according to the following formulas (Eqs. 1-3):

(1)

A V mPa \cdot s = 1 / 2 \times 600 r / m i n

(2)

P V (mPa \cdot s) = 600 r / m i n - 300 r / m i n

(3)

Y P Pa = A V - P V

2.4.3. Evaluation of drilling fuid filtration performance

The medium-pressure filtration loss (FL/API) of the drilling fluid at room temperature was measured using a medium-pressure filter press (Model ZNS-5A, Qingdao Chuangmeng Instrument Co., Ltd., China). The sealing performance of the equipment was ensured prior to testing. A 350 mL sample of drilling fluid was poured into the chamber, and a filter paper was placed on top. After assembling the instrument, a pressure of 100 psi (0.69 MPa) was applied to the chamber, and timing was started. The volume of filtrate passing through the filter paper within 30 min was collected and measured, and the thickness of the filter cake formed on the filter paper was recorded.

To simulate high temperature and high-pressure conditions, a high temperature high-pressure (HTHP) filter press (Model 1212, Qingdao Chuangmeng Instrument Co., Ltd., China) was used to measure the HTHP filtration loss (FL/HTHP) of the drilling fluid. The test was conducted at a temperature of 180°C under an applied pressure of 3.5 MPa. The filtrate volume under these conditions was measured accordingly.

2.4.4. Evaluation of filtration loss reduction performance

(1)

The sealing performance of the filter loss reduction agent was tested using a medium-pressure sand bed experimental device. The water-based drilling fluid was prepared in advance, and 1.0 wt%, 2.0 wt%, and 3.0 wt% fluid loss reducers were added, respectively. Stir evenly with a high-speed mixer and then age at 180°C for 16 h. The cleaned and dried quartz sand is loaded into the sealing device and filled by tapping and compaction. Then add the aged drilling fluid. Introduce nitrogen and apply a pressure of 0.69 MPa. Open the valve and start timing. Record the volume of filtered liquid lost within 30 min to evaluate the sealing effect.
(2)

Different concentrations of fluid loss reduction agents were added to the drilling fluid, respectively, and it was aged at 200°C for 16 h. The filtration loss performance of the additive under normal temperature and pressure and high-temperature and -pressure conditions was tested, respectively, using the API filtration loss tester and the high-temperature and -pressure filtration loss tester.
(3)

The sealing performance and permeability of the filter cake were evaluated using a GGS42-2F permeability and sealing tester (Qingdao Chuangmeng Instrument Co., Ltd., China) under a differential pressure of 0.7 MPa and room temperature, following the SY/T 5162-2014 industry standard. The fluid loss of the drilling fluid under a certain pressure was measured, and the sealing effect and anti-fluid loss performance of the additive were analyzed.

2.4.5. Microstructure analysis of mud cake surface

The formed mud cakes were dried at room temperature. The surface morphology of the mud cakes was characterized using a scanning electron microscope (SEM) to observe their microstructural features.

3. Results and Discussion

3.1. Fourier transform infrared analysis

The molecular structure and chemical composition of the fluid loss reducing agent material were analyzed by FTIR spectroscopy. The infrared spectrum of HTS-COFL has been shown in Figure 3, The peaks at 3342.76 cm⁻¹ and 3193.97 cm⁻¹ correspond to the N-H (amine) stretching vibrations in AM and AMPS. The molecule of DMDAAC contains multiple C-H bonds, particularly in its methyl (-CH₃) and methylene (-CH₂) structures. It also contains two methyl groups and an allyl group, which include saturated hydrocarbon bonds. The intense C-H stretching vibration observed at 2929.07 cm⁻¹ corresponds to the stretching vibration of C-H bonds in alkyl groups. The peaks observed at 1653.80 cm⁻¹ and 1608.50 cm⁻¹ may be associated with the stretching vibrations of C=O (carbonyl) and C=C (carbon-carbon double bond) groups present in AM and ACMO, respectively. The peak at 1447.71 cm⁻¹ corresponds to the bending vibration of the C-H bond. The peak at 1182.64 cm⁻¹ is attributed to the S=O (sulfonic group) stretching vibration in AMPS. The characteristic peak at 1108.18 cm⁻¹ corresponds to the C-O-C stretching vibration within the cyclic ether structure of ACMO. The peak at 1037.22 cm⁻¹ corresponds to the C-N stretching vibration in DMDAAC. The FTIR analysis confirms the presence of characteristic peaks corresponding to the expected functional groups in HTS-COFL, indicating that the synthesized material meets the design requirements.

FTIR spectroscopic analysis of HTS-COFL.

3.2. Thermogravimetric analysis

For drilling in deep formations, the durability of the fluid loss reducer’s thermal resistance is critically important. It must remain stable without decomposition under high-temperature and -pressure conditions, while maintaining superior fluid loss reduction performance. Figure 4 shows the TGA of HTS-COFL. The graph illustrates the mass changes of the sample at different temperatures, providing insights into its decomposition behavior. From the graph, it can be observed that the sample experiences mass loss at 79.3°C, 290.5°C, 314.7°C, and 384.0°C. These temperature points correspond to the decomposition stages of different polymer components in the sample. The total mass loss is approximately 83.36%. The mass loss can be roughly divided into four stages. As the temperature rises from room temperature to 79.3°C, the mass loss rate is approximately 4.25%/min. This mass loss is attributed to the evaporation of water during the polymer synthesis process or the removal of a small amount of residual solvent, representing the elimination of volatile components. When the temperature rises to 290.5°C, the rate of mass loss attains 10.19%/min. This is because AM-based polymers typically begin to decompose between 200°C and 300°C, causing the long-chain segments of the HTS-COFL polymer to break and undergo thermal degradation. At 314.7°C, a significant mass loss occurs with a loss rate of 17.36%/min. During this stage, the main chains of the polymer begin to break, accompanied by the thermal degradation of certain functional groups, such as quaternary ammonium and sulfonic acid groups, resulting in a notable weight loss. At 384.0°C, the mass loss rate reaches 14.04%/min. At this stage, the main chains of the HTS-COFL polymer completely degrade, including the backbone and functional groups of AM compounds, AMPS, and quaternary ammonium salts. The decomposition of sulfur- and nitrogen-containing groups accelerates significantly during this phase, producing a large amount of volatile products, which further intensifies the mass loss.

3.3. Proton nuclear magnetic resonance analysis

The functional groups grafted onto the polymer backbone were analyzed using the ¹H NMR (Figure 5). The chemical shifts for C=O and N-H in AM are typically in the lower range and thus do not appear in the hydrogen spectrum. Proton signals from alkenes usually do not persist after polymerization, so corresponding peaks are also absent. The peaks in the chemical shift range of 1.0-2.0 ppm correspond to the methyl (-CH₃) groups on AMPS. These methyl groups are connected to the sulfonic acid group, confirming the successful grafting of this functional group onto the polymer backbone. A characteristic signal appearing near 3.0 ppm corresponds to the methyl protons of the -N(CH₃)₂ group in DMDAAC, which are deshielded by the adjacent nitrogen atom, resulting in a downfield shift. The -CH₂- groups in the morpholine ring of ACMO are located near oxygen atoms and are slightly affected by the deshielding effect, appearing in a higher field. The peaks in the 3.5-4.0 ppm range correspond to the -CH₂- groups in the ACMO morpholine ring.

3.4. Testing of rheological properties

3.4.1. Rheological properties testing of fluid loss reducer at different concentrations

AV represents the flow resistance of drilling fluid under a specific shear rate, serving as a critical indicator of the fluid’s flowability. PV reflects the fluid’s ability to resist deformation; higher PV indicates a greater shear stress required to initiate fluid flow. YP measures the tangential force caused by the relative motion between fluid layers. The magnitude of YP directly affects the flow characteristics and overall performance of the drilling fluid. The parameters AV, PV, and YP are the most straightforward indicators for evaluating the flowability of drilling fluids in the wellbore and their suspension capacity. Meanwhile, the API fluid loss value measures the permeability of the drilling fluid through a filter. Lower permeability indicates better protection for the wellbore and the formation.

As shown in Figure 6, different mass fractions (0.3, 0.5, 1.0, 1.5 wt%) of the fluid loss reducer were added to pre-prepared freshwater drilling fluids, and the changes of AV, PV, YP, and API fluid loss before and after hot rolling at 180°C. The research findings indicate that the fluid loss control agent exerts a notable impact on the rheological characteristics and fluid loss reduction of drilling fluids across various concentration levels. From Figures 6(a,b), it is evident that the AV and PV increase significantly with increasing concentration of the filter loss reducer, particularly before thermal aging. This is because the amide groups in the fluid loss reducer form hydrogen bonds with water molecules, thereby increasing the viscosity of the drilling fluid. After thermal aging at 180°C, the increase in AV and PV is less pronounced, indicating that high temperatures have a certain impact on the viscosity of the polymer fluid loss reducer. This is because the hydrogen bonds formed with water at high temperatures are partially broken, leading to a reduction in viscosity. Figure 6(c) shows that the YP decreases to some extent after aging. This reduction is attributed to the weakening of fluid structure stability in high-temperature environments. However, due to the presence of sulfonic acid and quaternary ammonium groups in the fluid loss reducer, the polymer can still maintain a certain degree of hydration with water molecules under high temperatures. Although high temperatures weaken the hydration, these functional groups help the polymer retain its hydrated state, enabling the drilling fluid to maintain some viscosity even after high-temperature hot rolling. Figure 6(d) shows that adding 0.3 wt% of the filter loss reducing agent can significantly reduce the API filter loss after hot rolling at 180°C. With this concentration, the API fluid loss of the base slurry decreases from 71.6 mL to 18 mL after hot rolling, representing a reduction of 74.8%. When the concentration of the fluid loss reducer reaches 1.5 wt%, the fluid loss after hot rolling is only 7.6 mL. This improvement is attributed to the introduction of sulfonic acid groups in the polymer, which enhance thermal resistance. Although a slight increase in fluid loss is observed at elevated temperatures, the polymer still maintains better performance compared to non-sulfonated counterparts. Meanwhile, the quaternary ammonium cation groups exhibit strong hydrophilicity and charge properties, enhancing the polymer’s adsorption capacity. These groups enable the polymer to bind with clay, forming a dense filter cake to reduce filtration loss. Overall, the fluid loss reducer demonstrates superior performance at concentrations of 0.5 wt% or higher.

Different concentrations of HTS - COFL drilling fluid rheological properties before and after aging: (a) AV, (b) PV, (c) YP, (d) Medium-pressure fluid loss.

3.4.2. Salt resistance performance of HTS-COFL

The rheological properties of the loss reducer with different salt concentrations were studied to evaluate its salt resistance. Figure 7(a) shows that the AV of the drilling fluid decreases significantly with increasing NaCl concentration. Before thermal aging, the viscosity gradually drops from approximately 30 mPa·s at 0% NaCl concentration to about 13 mPa·s at 20% NaCl concentration. After thermal aging at 180°C, the AV further decreased under the same salt concentration conditions, with a maximum reduction of 11 mPa·s. This reduction in viscosity is primarily attributed to the solubility of the polymer in high-salt environments and the contraction of the molecular chain structure. High concentrations of NaCl increase the ionic strength of the solution, reducing the solubility of the polymer chains in the solution, which leads to a decrease in AV. Thermal aging further exacerbates the depolymerization or degradation of the polymer chains, causing an additional reduction in viscosity. Similar to AV, PV also decreases with increasing NaCl concentration. Figure 7(b) shows that the PV of the unaged samples decreases from approximately 17 mPa·s to about 10 mPa·s as the NaCl concentration increases. For the thermally aged samples, the reduction is even more pronounced, ultimately dropping to around 6-8 mPa·s. Figure 7(c) shows that the YP, which reflects the minimum stress required for the fluid to start flowing, decreases as the NaCl concentration increases. It drops from approximately 13 Pa before aging to about 8 Pa at 20% NaCl concentration. After thermal aging, the YP further decreases to 6-7 Pa under the same salt concentration conditions. Figure 7(d) shows that the filtrate volume increases with rising NaCl concentration. Before thermal aging, it increases from approximately 8 mL to about 10.5 mL. After thermal aging, the filtrate volume rises further to over 11 mL. The fluid loss control ability of the fluid loss reducer weakens under high-salt and high-temperature conditions. Overall, the fluid loss reducer demonstrated good salt resistance. When the NaCl concentration increased to 20%, the fluid loss before thermal aging increased by only 1.7 mL compared to the sample contaminated with 5% NaCl. Although thermal aging caused a slight increase in fluid loss, no significant deterioration was observed. Even under 20% NaCl contamination after aging, the fluid loss remained as low as 11.3 mL, indicating that the fluid loss reducer can effectively resist the adverse effects of high salinity up to 20%.

Rheological properties of drilling fluids containing 1wt% HTS-COFL at different NaCl concentrations: (a) AV, (b) PV, (c) YP, (d) Medium-pressure fluid loss.

Due to the strong polarity of the sulfonic acid group provided by the AMPS molecule, it dissociates into anions in aqueous solutions, attracting cations (Na⁺) to form ion pairs. This reduces the interference of salt on the polymer chains. The DMDAAC molecule provides cationic groups that can form ionic bonds with Cl^-, offsetting some of the effects of Cl^-on the polymer chains. The synergistic action of cationic and anionic groups creates a charge-balanced structure, enhancing the stability of the polymer under high-salt conditions [26]. The fluid loss reducer combines the charge balance of AMPS and DMDAAC, the steric hindrance and hydrophobicity of ACMO, and the structural framework of AM to form a polymer with strong salt resistance. However, under the condition of high salt and high temperature, the synergistic effect of these functional groups was weakened.

3.4.3. Calcium resistance performance of HCT-COFL

With the fluid loss reducer dosage fixed at 1%, the changes in the rheological properties of the drilling fluid under the addition of different concentrations of CaCl₂ were tested. Figure 8(a) shows that before thermal aging, as the CaCl₂ concentration increases from 0 wt% to 2.0 wt%, the AV gradually decreases, dropping from 32 mPa·s to 15 mPa·s. This indicates that the presence of calcium ions progressively reduces the AV of the drilling fluid. After thermal aging, within the same calcium ion concentration range, the AV decreases from 22 mPa·s to 5 mPa·s. Similarly, the PV follows a trend similar to that of the AV, as shown in Figure 8(b). As the concentration of CaCl₂ increases, the overall viscosity decreases. When the CaCl₂ concentration reaches 1.5 wt%, the AV decreases from 18 mPa·s before thermal aging to 12 mPa·s after thermal aging, and the PV decreases from 10 mPa·s to 6 mPa·s. At a CaCl₂ concentration of 2.0 wt%, the AV drops significantly from 15 mPa·s to 5 mPa·s, and the PV declines from 9 mPa·s to 4 mPa·s after thermal aging. This indicates that when the CaCl₂ concentration exceeds 1.5 wt%, there is a significant reduction in AV and PV, reflecting a deterioration in the rheological properties of the drilling fluid. Figure 8(c) shows that when the CaCl₂ concentration does not exceed 1.5 wt%, the YP maintains a certain level before and after thermal aging. At a CaCl₂ concentration of 1.5 wt%, the YP is 8 Pa before thermal aging and decreases to 6 Pa after thermal aging. However, when the CaCl₂ concentration reaches 2.0 wt%, the YP drops significantly from 6 Pa before thermal aging to 1 Pa after thermal aging. Figure 8(d) shows that the fluid loss increases gradually with rising CaCl₂ concentration, with a more pronounced effect after thermal aging. When the CaCl₂ concentration does not exceed 1.5 wt%, the fluid loss reducer demonstrates good fluid loss control, with only a slight increase in fluid loss before and after aging. However, when the CaCl₂ concentration exceeds 1.5 wt%, the fluid loss after rolling increases sharply. These results indicate that the fluid loss reducer is capable of withstanding calcium salt concentrations up to 1.5 wt%.

Rheological properties of 1wt% HTS-COFL drilling fluid at different CaCl2 concentrations: (a) AV, (b) PV, (c) YP, (d) Medium-pressure fluid loss.

Due to the introduction of sulfonic acid group(-SO₃⁻) on the fluid loss agent of polymer chain, the negatively charged groups produce electrostatic repulsion. Since Ca²⁺ carries a positive charge, it is repelled when approaching the negatively charged sulfonic acid groups. This repulsion helps resist the intrusion of calcium ions to a certain extent, reducing their disruptive effects on the polymer network. The electrostatic repulsion also reduces the adsorption of calcium ions onto the polymer chains, preventing crosslinking between chains. This helps maintain the polymer’s solubility and rheological properties [27]. Additionally, the polymer chain contains positively charged ammonium chloride groups (-N⁺(CH₃)₂ Cl⁻). These cations can form electrostatic coordination complexes with negatively charged groups in the solution, stabilizing the polymer structure. The presence of these groups can partially compete with calcium ions for binding to the sulfonic acid groups, thereby mitigating the erosion of the polymer structure by calcium ions. This enhances the stability of the polymer in high-calcium environments. The morpholine ring introduced from N-acryloyl morpholine is a relatively large molecular structure. Incorporating this group into the polymer chain creates a steric hindrance effect. This steric hindrance prevents Ca²⁺ from approaching the polymer chain and disrupting its structure, thereby enhancing its resistance to calcium contamination. The steric hindrance not only limits direct contact between calcium ions and the polymer but also increases the polymer’s overall volume, improving its high-temperature and high-calcium tolerance.

3.4.4. Temperature resistance of HST-COFL

To investigate the thermal stability of the fluid loss reducer, drilling fluid samples were aged at various temperatures (160°C, 170°C, 180°C, 200°C, and 220°C) for 16 h using a hot rolling oven. The rheological and filtration properties were then measured to assess the impact of temperature variation. As shown in Figure 9, the filtration loss data of different concentrations of filtration loss reducers (1.0 wt%, 1.5 wt%, 2.0 wt%) at varying aging temperatures are presented. As shown in Figure 9(a), the fluid loss reducer at 1.0 wt% effectively limits fluid loss to 8 mL before aging, indicating strong performance in controlling fluid loss. After aging, the fluid loss slightly increases compared to the pre-aging value. Furthermore, as the increase in aging temperature increases, fluid loss progressively rises- from 8.2 mL at 160°C to 12.6 mL at 220°C. Notably, after aging at 220°C, the fluid loss increased by 57.5% compared to the pre-aging value, indicating a significant rise in fluid loss. In contrast, after aging at 200°C, the fluid loss increased by only 27.5%. In Figures 9(b and c), the fluid loss of the drilling fluid after aging at 220°C increased by 64.1% and 71.4%, respectively, compared to before aging. This indicates that as the concentration of the fluid loss reducer increases, the drilling fluid demonstrates excellent fluid loss reduction performance even under aging conditions at 200°C. Figure 9(d) shows the HTHP (180°C) fluid loss for different concentrations of the fluid loss reducer across varying aging temperature ranges. The HTHP fluid loss at a concentration of 1 wt% fluid loss reducer is the highest and increases significantly with temperature. After aging at 220°C, the HTHP fluid loss reaches 28.6 mL. The 1.5 wt% concentration performs better, with HTHP fluid loss values lower than those of the 1 wt% concentration at all temperatures, reaching a peak of 27.4 mL at 220°C. The 2 wt% concentration exhibits the lowest HTHP fluid loss values, indicating the best performance. Although the fluid loss gradually increases with rising temperature, it remains below 26 mL even at 220°C.

Filtration performance of HTS-COFL at different concentrations and temperatures: (a) Medium-pressure fluid loss before and after aging with 1 wt% HTS-COFL at different temperatures, (b) Medium-pressure fluid loss before and after aging with 1.5 wt% HTS-COFL at different temperatures, (c) Medium-pressure fluid loss before and after aging with 2 wt% HTS-COFL at different temperatures, (d) High-temperature and high-pressure fluid loss after aging at different temperatures (test conditions for high temperature and high-pressure fluid loss: 180°C under 3.5 MPa pressure).

The fluid loss additive exhibits the best performance in fluid loss reduction at higher concentrations. After thermal aging, all concentrations show an increase in fluid loss, with the 2 wt% concentration being the most stable, indicating its superior thermal stability. The 2 wt% concentration also shows optimal performance under extreme thermal and pressure conditions, with a markedly reduced fluid loss, demonstrating its suitability for such demanding environments. However, as the dosage increases, material costs will also rise. This fluid loss additive demonstrates excellent fluid loss reduction performance under certain conditions, even at concentrations below 2 wt%. The dosage can be adjusted based on on-site construction parameters and bottom-hole conditions. For deep, high-temperature wells, the concentration can be appropriately increased. Conversely, for formations with lower temperature requirements, the dosage can be reduced accordingly.

3.5. Analysis of temperature and salt resistance mechanism of HTS-COFL

Schematic illustration of the fluid loss control mechanism of the high-temperature-resistant polymer synthesized from AM, AMPS, DMDAAC, and ACMO (Figure 10). The polymer adsorbs onto clay particles through electrostatic interactions, hydrogen bonding, and ionic coordination. The AMPS segments provide strong hydration and salt resistance; DMDAAC enhances cationic interaction with negatively charged clays; AM ensures structural flexibility; and ACMO contributes thermal stability. These interactions promote the formation of a compact and low-permeability filter cake on the wellbore wall, effectively reducing fluid loss under high-temperature and high-salinity conditions.

Mechanism of action of the fluid loss additive during the drilling process.

AM contains a strongly polar amide group capable of forming hydrogen bonds with water molecules. At high temperatures, the hydrogen bonds and interactions between molecular chains help maintain structural stability. Even under high temperature conditions, the amide group does not undergo significant thermal decomposition or degradation, allowing the polymer to retain its viscosity and functionality at elevated temperatures [28]. The polar characteristics of the amide group enable it to maintain good hydrophilicity in aqueous solutions, which enhances the polymer’s solubility in saline water and prevents polymer precipitation caused by salting-out effects.

The introduction of sulfonic acid groups from AMPS monomers provides negatively charged sulfonic groups that can interact electrostatically with cations (such as Na⁺ and Ca²⁺) in drilling fluids. This interaction mitigates the impact of these ions on the polymer, enhancing the stability of the fluid loss additive in saline and calcium ion-rich environments [29,30]. Additionally, the strong hydrophilicity of the sulfonic acid groups helps the polymer maintain a robust hydration layer in high salinity or high-calcium environments. This prevents aggregation or coagulation between polymer chains, thereby preserving the dispersion of the fluid loss additive. Sulfonic acid groups remain stable under high temperature conditions without undergoing decomposition. The charge properties and hydrogen bonding of the sulfonic acid groups enhance the stability of polymer chains, preventing molecular chain breakage or structural degradation caused by high temperatures [31]. In addition, the hydrophilicity of sulfonic acid groups helps the polymer maintain good solubility in high-temperature environments, preventing dehydration and precipitation of the polymer.

The cationic groups introduced from DMDAAC monomers can interact with anionic minerals in drilling fluids (such as clay or negatively charged filter cake particles), forming a stable adsorption layer [32,33]. The cationic groups help neutralize the negative effects of Ca²⁺ in drilling fluids, preventing calcium ions from cross-linking with the polymer and thereby reducing the damage caused by calcium ions to the fluid loss additive. Moreover, these groups enhance the polymer’s adhesion and stability in high salinity or high-calcium conditions, effectively preventing the fluid loss additive from failing in such environments.

ACMO contains functional groups with amide and cyclic amine groups. This structure endows it with strong hydrophilicity and the ability to form hydrogen bonds with water molecules [34]. The amino group carries a slight positive charge, which allows it to maintain the polymer’s hydration state in high-salt environments through electrostatic interactions with salt ions, particularly sodium ions (Na⁺). This helps prevent salting-out phenomena and ensures the stable dispersion of the polymer. The morpholine ring in ACMO is a nitrogen-containing six-membered heterocyclic structure with inherent rigidity. The cyclic structure restricts molecular free motion at high temperatures, contributing to improved overall chemical and thermal stability [35].

3.6. Evaluation of the fluid loss control performance of HTS-COFL

3.6.1. Medium-pressure sand bed filtration performance evaluation

The sealing capability of the water-based drilling fluid additive was assessed using a medium-pressure sand bed device, which simulates the formation’s pore structure under specific pressure conditions, to investigate its influence on fluid loss and sand bed permeability. Quartz sand with a mesh size of 100-140 was poured into a tempered glass column up to the 350 mL mark, followed by tapping the column wall and compacting the sand bed to minimize pore non-uniformity. Then, the prepared drilling fluid sample was slowly poured in, ensuring uniform penetration through the sand bed. Finally, nitrogen gas was applied at a pressure of 0.69 MPa (100 psi), the valve was opened to start timing, and the filtration test began. The filtrate volume was recorded every 5 min, with a total experiment duration of 30 min.

As shown in Figure 11, when no fluid loss additive was added, the drilling fluid exhibited poor sealing ability, with a fluid loss of 142 mL in 30 min, indicating severe filtration. When 1 wt% HTS-COFL was introduced, the 30-min fluid loss decreased compared to the base fluid without HTS-COFL, demonstrating the additive’s effectiveness. At an HTS-COFL concentration of 3 wt%, the 30-min filtrate volume was reduced to only 51 mL, showing the best sealing performance. An increased dosage of HTS-COFL significantly enhanced plugging efficiency in the sand bed pores, reducing the permeability of the drilling fluid and achieving optimal filtration control. Compared with the base drilling fluid, HTS-COFL significantly improved fluid loss control by forming a dense barrier.

Medium-pressure sand bed experiment-Variation of fluid loss with time at different HTS-COFL concentrations.

3.6.2. Evaluation of filtration performance under atmospheric and elevated temperature-pressure conditions

Water-based drilling fluids without any fluid loss additive were supplemented with varying concentrations of HTS-COFL and subjected to thermal aging at 200°C for 16 h. Subsequently, the API and HTHP (180°C) fluid loss values were measured, with the results illustrated in Figure 12. With increasing HTS-COFL concentration, both API and HTHP fluid loss decreased significantly, indicating the excellent sealing performance of the fluid loss additive. Without HTS-COFL, the HTHP fluid loss reached 68 mL, whereas at a concentration of 3 wt%, the fluid loss decreased to 8.6 mL. Similarly, the API fluid loss dropped from 16.4 mL to 3.5mL. This indicates that HTS-COFL can effectively reduce the permeability of drilling fluid and significantly improve the loss reduction effect under normal pressure and high-temperature and high-pressure conditions. Furthermore, the fluid loss performance improves as the concentration increases.

Filtration performance evaluation of HTS-COFL at different concentrations under atmospheric and HTHP conditions.

3.6.3. Evaluation of the permeability plugging performance of HTS-COFL.

To evaluate the blocking performance of the synthesized filter loss-reducing agent, a blocking experiment was conducted using a permeability plugging apparatus (PPA). Pre-hydrated base slurry was prepared, and different concentrations of the fluid loss additive (e.g., 0.5 wt%, 1.0 wt%, 2.0 wt%, 3.0 wt%) were added. The mixture was stirred evenly and then aged at 200°C for 16 h. Subsequently, two ceramic filter disks with different permeabilities (1 mD and 10 mD) were selected and installed in the PPA device, ensuring a proper seal. The aged drilling fluid was then injected into the test chamber, and a set pressure of 3.5 MPa (500 psi) was applied at different temperatures (180°C and 200°C). The experiment lasted for 30 min, and the amount of filtrate was measured over various time intervals (Figure 13).

PPA filtration performance evaluation of HTS-COFL under different temperature and permeability conditions.

As shown in Figure 13, the filtrate volume decreased significantly with increasing additive concentration. At 180°C using the 1 mD disc, the filtrate volume was reduced from 6.1 mL (blank) to 2.9 mL at 1.0 wt%, and further to 2.3 mL at 3.0 wt%. The plugging efficiency increased accordingly, reaching over 60% at 3.0 wt%. However, at 200°C, the sealing performance slightly declined, with filtrate volumes increasing by approximately 20-30% compared to 180°C under the same conditions. Additionally, when using the 10 mD disc, fluid loss remained higher across all concentrations, indicating that bridging and sealing large pore throats is more difficult. These results confirm that while HTS-COFL has good high-temperature sealing capabilities, its effectiveness depends strongly on both permeability and thermal conditions. Appropriate dosage adjustment is essential for optimal field performance.

3.7. Filter cake analysis

Performing microstructural analysis of drilling fluid filter cakes using SEM. Figure 14 presents the changes in the filter cake surface before and after aging at 180°C. Figure 14(a) shows the filter cake without the addition of a fluid loss reducer. The filter cake surface exhibits high roughness, uneven particle distribution, a loose surface structure, and poor compactness. It can be observed that the surface contains numerous pores, and the connectivity between particles is relatively weak. Figure 14(b) shows that after adding the fluid loss reducer, the filter cake surface becomes significantly smoother, more uniform, and denser. There is noticeable connectivity between particles, and no obvious pores are present. Figure 14(c) shows that after high temperature aging, the filter cake becomes lighter in color but remains uniform. This color change may result from slight chemical or physical alterations in the structure during the aging process, though the overall impact is minimal. The filter cake surface remains relatively smooth and uniform before and after aging, with no visible cracks or protrusions, indicating good overall integrity.

Filter cake image with 1 wt% HTS-COFL additive. (a) Mud cake and SEM images of the sample after aging without HTS-COFL. (b) Mud cake and SEM images of the sample before aging with 1% HTS-COFL. (c) Mud cake and SEM images of the sample after aging with 1% HTS-COFL.

From the SEM images of the filter cake, it is evident that after the addition of the filter loss reducing agent, a smooth thin film forms on the clay surface. This occurs because the fluid loss reducer creates bonds between the filter cake particles through adsorption and polymerization, continuously encapsulating the clay molecules. This significantly enhances the connectivity between particles, thereby the porosity of the filter cake is reduced and the structure is more compact. The fluid loss reducer forms a low permeability filter cake on the filter cake surface, significantly reducing its permeability and enhancing the plugging efficiency of the drilling fluid. In the SEM images of the filter cake after aging, the particles become more uniform. With increasing temperature, the viscosity first slightly increases due to enhanced polymer chain interactions, followed by a gradual decrease likely caused by thermal disruption of the network structure

Figure 15 presents the macroscopic images and SEM microstructures of the filter cakes formed under high-salinity and high-calcium contamination at a polymer dosage of 1 wt%. Under 20% NaCl contamination, the filter cake surface before aging (Figure 15a) appears smooth, uniform, and well-polished, indicating that the fluid loss additive can form a thin and compact filter layer even in high salinity conditions. This suggests that the additive maintains excellent dispersibility and prevents particle aggregation in the presence of Na⁺ ions. After hot rolling at 180°C (Figure 15b), the surface becomes slightly shrunken but still retains good uniformity and integrity. No visible cracks are observed, and only small pores appear. Although the cake thickness increases slightly after aging, the structure remains intact, reflecting the high-temperature and high-salinity resistance of the additive.

Effect of NaCl and CaCl2 contamination on the morphology of filter cakes before and after thermal aging. (a) Mud cake and SEM images of the sample before aging with 20% NaCl. (b) Mud cake and SEM images of the sample after aging with 20% NaCl. (c) Mud cake and SEM images of the sample before aging with 1.5% CaCl2. (d) Mud cake and SEM images of the sample after aging with 1.5% CaCl2.

The corresponding SEM images reveal that, prior to aging, clay particles are tightly packed with no significant cracks or large voids, confirming that the additive promotes crosslinking or tight binding between clay particles through surface adsorption. After aging, particle connections become looser, but the microstructure remains compact without severe pore formation. These results indicate that the additive preserves the density and sealing ability of the filter cake under harsh NaCl and thermal conditions, thus exhibiting excellent salt and temperature resistance.

Under 1.5% CaCl₂ contamination (Figures 15c,d), the surface morphology of the filter cake before aging is similar to that under NaCl conditions. However, after hot rolling, the surface uniformity decreases. The presence of Ca²⁺ ions disturbs the electrostatic interactions among clay particles and enhances particle bridging, altering the filter cake formation process. From the SEM images, it is observed that, before aging, the particle distribution is relatively uniform, but the binding force is weaker than in the NaCl system. Small pores are present, which may be caused by competitive adsorption between Ca²⁺ ions and the polymer’s functional groups, reducing particle cohesion. After aging, the cake becomes rougher, with more noticeable small pores and looser interparticle connections, suggesting partial thermal degradation of the additive in the presence of calcium ions.

In summary, at 1 wt% dosage, the fluid loss additive exhibits superior salt tolerance, maintaining a uniform and dense filter cake even after aging at 180°C in a 20% NaCl environment. Although the performance under 1.5% CaCl₂ contamination is slightly inferior, the filter cake still retains its basic integrity after aging, indicating a considerable level of calcium resistance. These findings suggest that the additive has broad applicability in salt- and calcium-rich formations, and its dosage can be flexibly adjusted according to field conditions.

4. Conclusions

By introducing different functional groups (including sulfonic groups, quaternary ammonium groups, and morpholine ring groups) into the polymer structure, a fluid loss reducer, HTS-COFL, was synthesized, which can remain stable under high temperature (220°C), high salinity, and high calcium conditions. Experimental results show that adding HTS-COFL at a 0.5% concentration to the base slurry can reduce fluid loss by 50%, with the API fluid loss increasing by only 1.9ml after aging at 180°C. At a 2.0% concentration, HTS-COFL reduces fluid loss by 75.6%, with the API fluid loss increasing by only 0.9ml after aging. It demonstrates excellent temperature resistance and fluid loss control capabilities. Additionally, HTS-COFL effectively controls fluid loss in environments with 1.5% CaCl₂ and 20% NaCl concentrations, indicating strong salt and calcium resistance.

Synergistic effect of multifunctional functional groups. The synergistic interaction of different functional groups (such as sulfonic groups, quaternary ammonium groups, and morpholine rings) in the fluid loss reducer enables HTS-COFL to maintain good stability and rheological properties under high temperature, high salinity, and high-calcium conditions. The charge-balanced structure of the sulfonic and quaternary ammonium groups enhances the polymer’s salt and calcium resistance, while the morpholine ring provides steric hindrance to improve high-temperature stability.

After adding HTS-COFL, the surface of the mud cake becomes smooth and flat, with significantly reduced porosity. HTS-COFL forms a low-permeability, dense filter cake on the wellbore surface, effectively reducing the infiltration of the aqueous phase in the drilling fluid. This enhances the plugging performance of the drilling fluid, helping to maintain wellbore stability and prevent wellbore collapse.

The application concentration of HTS-COFL is adjustable to accommodate different formation environments. The optimal performance is achieved at a concentration of 1.5-2.0 wt%, but even at a lower concentration of 0.5 wt%, it exhibits significant fluid loss reduction effects. This allows the dosage of HTS-COFL to be flexibly adjusted according to actual downhole conditions; higher concentrations can be used for high-temperature deep wells, while lower amounts can suffice for shallow wells with lower temperature requirements, thereby controlling costs.

Acknowledgment

The authors are sincerely grateful for the support of the following funds:

1.

Open Foundation of Cooperative Innovation Center of Unconventional Oil and Gas, Yangtze University (Ministry of Education & Hubei Province), No. UOG2024-10.
2.

Hubei Province Science and Technology Plan Project (Key R&D Special Project), China, Grant No. 2023BCB070.
3.

Key R&D Program Project in Xinjiang, China, Grant No.2022B01042.
4.

Guiding Project of Scientific Research Program of Education Department of Hubei Province, China, Grant No. B2023024.
5.

Open Fund of National Key Laboratory of Oil and Gas Reservoir Geology and Exploitation (Southwest Petroleum University), Grant No. PLN2023-03.

CRediT authorship contribution statement

Peng Xu: Conceptualization; Data Curation; Methodology; Project Administration; Writing/Review & Editing. Tao Peng: Data Curation; Investigation; Methodology; Validation; Writing/Original Draft Preparation. Lei Pu: Investigation; Project Administration; Supervision; Visualization. Jing Li: Conceptualization; Formal Analysis; Visualization. Bangzhe Wang: Data Curation; Investigation. Jingwei Liu: Investigation; Validation.

Declaration of competing interest

The authors declare that they have no known competing financialinterests or personal relationships that could have appeared to influencethe work reported in this paper.

Declaration of generative AI and AI-assisted technologies in the writing process

The authors confirm that there was no use of artificial intelligence (AI)-assisted technology for assisting in the writing or editing of the manuscript and no images were manipulated using AI.

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Synthesis of a zwitterionic quaternary ammonium polymer and its application in fluid loss control for water-based drilling fluid

Abstract

Keywords

Fluid loss additive

High-temperature and salt-resistant

Polymer

Water-based drilling fluids

Zwitterion

1. Introduction

2. Materials and Methods

2.1. Materials

2.2. Synthesis of HTS-COFL

2.3. Structural characterization of HTS-COFL

2.3.1. Fourier transform infrared analysis

2.3.2. Thermogravimetric analysis.

2.3.3 Proton nuclear magnetic resonance analysis

2.4. Performance assessment of HTS-COFL drilling fluid

2.4.1. Preparation of drilling fluid

2.4.2. Measurement of rheological properties.

2.4.3. Evaluation of drilling fuid filtration performance

2.4.4. Evaluation of filtration loss reduction performance

2.4.5. Microstructure analysis of mud cake surface

3. Results and Discussion

3.1. Fourier transform infrared analysis

3.2. Thermogravimetric analysis

3.3. Proton nuclear magnetic resonance analysis

3.4. Testing of rheological properties

3.4.1. Rheological properties testing of fluid loss reducer at different concentrations

3.4.2. Salt resistance performance of HTS-COFL

3.4.3. Calcium resistance performance of HCT-COFL

3.4.4. Temperature resistance of HST-COFL

3.5. Analysis of temperature and salt resistance mechanism of HTS-COFL

3.6. Evaluation of the fluid loss control performance of HTS-COFL

3.6.1. Medium-pressure sand bed filtration performance evaluation

3.6.2. Evaluation of filtration performance under atmospheric and elevated temperature-pressure conditions

3.6.3. Evaluation of the permeability plugging performance of HTS-COFL.

3.7. Filter cake analysis

4. Conclusions

Acknowledgment

CRediT authorship contribution statement

Declaration of competing interest

Declaration of generative AI and AI-assisted technologies in the writing process

References

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