Application of a Novel Temperature-Sensitive Polymer PNA-SiO₂ as a Rheological Agent in Geothermal Drilling

Abstract

In geothermal drilling, the significant rheological deterioration of biopolymer drilling fluids can lead to decreased cutting-carrying efficiency and fluctuations in annulus pressure, which can easily result in unpredictable downhole accidents. To address the challenges, this study innovatively introduces temperature-sensitive monomers (NIPAM) and nanosilica into molecular chains based on temperature response effects and adsorption stability to counteract the negative effects of temperature and salt ions, aiming to develop a rheological agent (PNA-SiO₂) that is resistant to high temperature and salt. The molecular structure and thermal stability of PNA-SiO₂ were characterized by FT-IR and TGA, and it was demonstrated to have the stability of the molecular main chain within 317 °C. According to rheological and filtration studies, PNA-SiO₂ effectively addresses the issues of high-temperature viscosity attenuation and a sharp rise in the filtration volume of bentonite mud by aggressively adsorbing, creating a stable thixotropic network, and enhancing molecular repulsion. After aging at 60–180 °C, the drilling fluid with 2–4% PNA-SiO₂ has excellent rheology (AV ≥ 57.5 mPa·s, PV ≥ 42 mPa·s, Gel_10 min ≥ 1.533 Pa) and filtration (FL_API ≤ 9.6 mL) properties that fully satisfy API requirements. The H–B model is the preferred model to accurately describe the rheology behavior of PNA-SiO₂ drilling fluids. Moreover, under the comprehensive influence of Na⁺ on the interlayer spacing of bentonite and the thickness of the diffusion bilayer, PNA-SiO₂ has applicability in high-temperature saturated saline water. After aging at 150 °C and 5–36% NaCl, the PNA-SiO₂ drilling fluid exhibits stable viscosity (AV ≥ 55 mPa·s, PV ≥ 44 mPa·s) and low filtration volume (≤9.6 mL). In conclusion, PNA-SiO₂ is used as a rheological and fluid loss agent, offering a cost-effective solution to the technical issues of severe leakage and inadequate cutting-carrying capacity encountered by geothermal drilling, which enables the safe and quick exploration of geothermal resources.

1. Introduction

Geothermal drilling has attracted increasing attention due to the rising demand for energy and the escalating environmental problems associated with the petroleum industry.¹⁻³ Drilling is the primary means of geothermal exploration and development, accounting for 40–60% of the total cost of geothermal projects.⁴ In drilling operations, drilling fluids are known as the lifeblood of drilling, which are utilized to cool and lubricate the drill bit, regulate formation pressure, transport cuttings to the surface, and enhance wellbore stability.^5,6

However, the primary obstacles to geothermal drilling operations are harsh reservoir conditions (high temperatures ≥150 °C, high mineralization, and even saturated brine erosion). Drilling fluid has numerous technical drawbacks in terms of preserving rheological stability and controlling filtration.⁷ For example, when the temperature increases from 40 to 100 °C, the viscosity of biopolymer drilling fluid (xanthan gum, starch, cellulose, etc.) decreases by more than 50% due to thermal decomposition.⁸⁻¹¹ It has also proven challenging to address the issues of viscosity attenuation and inadequate shear force with certain drilling fluids based on innovative graft polymers, copolymers, and inorganic composite materials.¹²⁻¹⁴ With the addition of 15% NaCl, the apparent viscosity (AV) of oligosaccharide grafted polymer drilling fluid decreased by 27.6%.¹⁵ The amphoteric polymer developed by Hamad et al. also experienced a shear force reduction at rising temperatures (≥200 °C).¹⁶ The aforementioned reduction in rheological characteristics results in a fall in the drilling speed and rock-carrying efficiency and causes variations in annular pressure. Evidence indicates that this will have an additional impact on leakage, leading to unpredictably occurring downhole mishaps.¹⁷⁻¹⁹ In conclusion, these circumstances have made the creation of rheological agents that are resistant to high temperatures and salts imperative.

Rheological agents interact with clay particles through van der Waals forces, hydrogen bonding, electrostatic forces, and intermolecular forces to achieve the effect of stabilizing viscosity and cutting of drilling fluid.²⁰ The innovation and optimization of monomers are key to enhancing the temperature and salt resistance of copolymers. In this study, a novel temperature-sensitive polymer (TSP) PNA-SiO₂ was designed as a drilling fluid rheology agent in this research, which was synthesized via free radical polymerization of N-isopropylacrylamide (NIPAM), 2-acrylamido-2-methyl-1-propenesulfonic acid (AMPS), and nanosilica (Nano-SiO₂).

The temperature-sensitive monomer (NIPAM) was first selected to form the main chain structure of the rheological agent. In principle, NIPAM has been proven to undergo hydrogen-bonding adsorption, molecular chain association, and hydrophilic/hydrophobic transformation with bentonite,²¹ which is beneficial for ensuring the suspension of cuttings. The temperature response effect of NIPAM was hoped to compensate for the degradation of high-temperature performance.^22,23 As shown in Figure 1, when the ambient temperature (T) is less than the response temperature (T_m), the NIPAM molecule forms a weak gel structure through the van der Waals force; when T > T_m, thermal disturbance increases the hydrophobicity of temperature-sensitive groups. After that, the NIPAM molecular chains create a cross-linked network structure with high strength, which raises the viscosity and produces a flat rheology.^24,25 The latest research also supports the application of NIPAM in high-temperature and high-salt environments. NIPAM–bentonite mixture exhibits stable flow and temperature-thickening properties at 40–70 °C.²⁶⁻³⁰ Fan et al. also found a rare high-temperature thickening phenomenon in NIPAM copolymers.³¹ At present, reports on NIPAM are mostly focused on temperatures below 100 °C, and there is a lack of data on its salt tolerance.

Figure 1.

Schematic diagram of the temperature response mechanism of TSP.

In 2024, Binqiang et al. introduced acrylamide and sodium 2-acrylamido-2-methylpropanesulfonate to thermosensitive monomers and developed a comb-shaped TSP. It achieved a breakthrough in salt resistance (20% NaCl).³² Inspired by this, AMPS monomers were selected. AMPS has high polymerization activity and is insensitive to salt, which is the key to enhancing salt resistance at high temperatures. The sulfonic acid groups of AMPS have strong hydration characteristics, which enhance the ion contamination resistance of copolymers by forming a solvation layer.^33,34 Besides, flocculation and sedimentation of the drilling fluid at temperatures exceeding 121 °C can also be resolved by AMPS.^35,36

Innovatively, KH570-modified hydrophilic Nano-SiO₂ has been introduced, with the hope of further enhancing high-temperature stability through adsorption and bridging. First, the high surface area of Nano-SiO₂ allows them to optimize particle–particle interactions and polymer viscoelasticity. Boyou et al. observed a 30.8–44% increment in cutting-carrying efficiency in Nano-SiO₂ drilling fluids, attributed to the colloidal interaction between Nano-SiO₂ and cuttings.³⁷ A polyethylene glycol-nanosilica composite (PEG-SiO₂) provides higher internal friction, fluid viscosity, and enhanced shear force for drilling fluids at 121 °C.³⁸ Second, the properties of nanoparticles are almost unaffected by temperature and salt ions. Wang et al. introduced Nano-SiO₂ onto the molecular chain of hydroxyethyl cellulose and obtained a rheological agent for 210 °C drilling fluids.³⁹ An anionic polymer with Nano-SiO₂ as the core was found to have a stability of up to 30 days in saturated saline and standard API saline (8 wt % NaCl + 2 wt % CaCl₂).⁴⁰ Last but not the least, hydrophilic Nano-SiO₂ has strong adsorption and unique bridging mechanisms in the bentonite system. Ma et al. first discovered the adsorption of Nano-SiO₂ on the surface of bentonite based on TEM and attributed it to the large number of hydrophilic adsorption groups on the surface.⁴¹ Zheng et al. further revealed the Nano-SiO₂ mechanism, in which aggregates (adsorption) at the branches of polymers (bridging) effectively reinforce the network stability.⁴²

In short, PNA-SiO₂ is anticipated to address the issue of significant degradation of drilling fluid rheology and filtration in geothermal formations according to the design of the molecular structure. The rheological and filtration properties of PNA-SiO₂-based drilling fluids at geothermal conditions (60–180 °C, 0–36% NaCl) were evaluated. The mechanism of interaction between PNA-SiO₂ and bentonite in the slurry was revealed through XRD, zeta potential, PSA, and TEM analysis.

2. Materials and Method

2.1. Materials

The NIPAM (AR, 99%), 2-acrylamido-2-methyl-1-propanesulfonic acid (98%), sodium bisulfite (AR), and ammonium persulfate (AR, ≥98%) were purchased from Shanghai Aladdin Biochemical Technology Co., Ltd. Anhydrous sodium carbonate (≥96%) and sodium hydroxide (≥96%) were purchased from Beijing Yili Fine Chemicals Co., Ltd. Sodium chloride (AR) was purchased from Sinopharm Chemical Reagent Co., Ltd. Sodium-based bentonite was purchased from Shandong Weifang Boda Bentonite Co., Ltd.

As shown in Figure 2, due to the presence of numerous hydroxyl groups on the surface of nanosilica particles and their high surface activity, they are prone to aggregation. To ensure the dispersibility and stability of nanomaterials in clean water, a KH570 surface modified nanosilica material (Nano-SiO₂) was selected for copolymerization, which was purchased from Jiangsu Xianfeng Nanomaterial Technology Co., Ltd. It appears as a fluffy white powder with a purity of 99% and a specific surface area of 140.21 m²/g.

Figure 2.

Modification principle of KH570 on nanosilica.

2.2. Preparation and Testing Methods

2.2.1. Synthesis of Temperature-Sensitive Polymers

Figure 3 depicts the PNA-SiO₂ synthesis procedure. First, NIPAM (11.3 g) and AMPS (20.7 g) were dissolved in 100 mL of deionized water. A NaOH solution (70 wt %) was used to adjust the solution’s pH to 7–8. Then, Nano-SiO₂ (2 g) was added, forming a homogeneous precipitate-free mixture. The mixture was transferred to a three-necked flask and heated for 20 min using a water bath (Model DF-101S, China) with constant N₂ protection and 300 rpm stirring. In the meantime, NaHSO₃ (20 mg) and (NH₄)₂S₂O₈ (30 mg) were dissolved in 5 mL of deionized water to prepare the initiator. Following the solution’s heating to 60 °C and the complete release of oxygen from the flask, the initiator was added and the reaction was continued for 2 h to obtain a milky white viscous liquid. After cooling, the product was dialyzed for a week in distilled water while it was in a dialysis bag with a molecular cutoff. The distilled water was replaced every day. NIPAM and AMPS have molecular weights of 113.16 and 207.25, respectively. Dialysis efficiently eliminates unreacted monomers to guarantee the purity of the final product. The TSP PNA-SiO₂ was then extracted by grinding the product into powder after it had been dried for 48 h at 60 °C in a blast drying oven (Model 101-2BS, China).

Figure 3.

Synthesis process of PNA-SiO₂.

2.2.2. Preparation of Drilling Fluid

2.2.2.1. Preparation of Bentonite Base Mud

Sodium-based bentonite (200 g) and Na₂CO₃ (12.5 g) were added to freshwater (5000 mL), stirred continuously at a speed of 300 rpm for 6 h, and stood for 24 h. Then the 4% prehydrated base mud was obtained.

2.2.2.2. Preparation of Drilling Fluid

Using a high-speed mixer (Model WT-2000C, China), 1–5% (mass ratio of base mud) of PNA-SiO₂ was added to bentonite base mud (300 mL) and agitated at 6000 rpm for 15 min. The PNA-SiO₂ drilling fluid was then obtained by aging the solution for 16 h at 60–180 °C. The PNA-SiO₂-containing saltwater drilling fluid was prepared with 3% PNA-SiO₂, bentonite base mud, and 5–36% NaCl. The fluid was aged for 16 h at 150 °C after being stirred for 15 min at 6000 rpm.

2.2.3. Tests of Drilling Fluids

2.2.3.1. Rheology Test

The rheology of the drilling fluids was tested using a six-speed rotating viscosimeter (Model ZNN-6, China). After recording the data at 600, 300, 200, 100, 6, and 3 rpm, the yield point (YP), plastic viscosity (PV), and AV were calculated using formulas 1–3.

The static shear force of the drilling fluid is measured by the following method: allowing the stirred drilling fluid to stand for 10 s and reading the maximum value at 3 rpm; stirring the drilling fluid again and standing for 10 min; and then recording the maximum value at 3 rpm. The initial gel strength (Gel_10 s) and final gel strength (Gel_10 min) were calculated by formulas 4 and 5.³⁶

1

2

3

4

5

AV and PV are measured in mPa·s; YP, Gel_10s, and Gel_10 min are measured in Pa; while θ₆₀₀, θ₃₀₀, and θ₃ are dimensionless readings from viscosity meters.

2.2.3.2. Filtration Property

According to the American Petroleum Institute (API) standard, the filtration property of the drilling fluid was measured by a medium-pressure filtration apparatus (Model ZNS-2, China), and the filtration volume within 30 min was recorded at a pressure of 100 psi.

2.3. Characterization Techniques

2.3.1. Fourier Transform Infrared (FT-IR) Spectroscopy Measurement

The chemical structure of PNA-SiO₂ was characterized by an FT-IR spectral analysis (Model INVENIOS, Germany Bruker). The tested wavenumber was 400–4000 cm^–1.

2.3.2. Thermal Gravity Analysis (TGA)

A thermogravimetric analyzer (Model INVENIOS, Germany Bruker) was used to evaluate the thermal stability of PNA-SiO₂. It was conducted under a N₂ atmosphere with a heating rate of 10 °C/min, and the heating range was 30–800 °C.

2.3.3. X-ray Diffraction (XRD)

XRD was used to evaluate the layer spacing of bentonite in the base mud. The drilling fluid samples were dried and ground into powders. Then, they were put into a mold to make tablets and tested in an XRD instrument (Model Bruker D8 ADVANCE, Germany). The scan angle was from 5° to 15°, and the scan speed was 4°/min. The layer spacing of bentonite was calculated by Bragg’s equation as shown in eq 6.

6

where d is the interlayer spacing, the unit is nanometer; n is the reflection series, which is 1; λ is the wavelength, which is 0.15406 nm; and θ is the incident angle of XRD.

2.3.4. Zeta Potential Analysis

Zeta potential analysis was used to test the electric potential of drilling fluids. Drilling fluids (10 mL) aged at different temperatures were retained and sequentially placed in a colorimetric dish and a Zeta potential instrument (Model ZETASIZER Nano ZS, Malvern, UK).

2.3.5. Particle Size Analysis (PSA)

Samples of aged base mud, aged PNA-SiO₂ drilling fluid, and aged PNA-SiO₂ drilling fluid containing NaCl were prepared. The particle size distribution of bentonite in the fluid sample was tested using an ultrahigh-speed intelligent particle size analyzer (Britain).

2.3.6. Transmission Electron Microscopy (TEM)

Solutions of 0.005% PNA-SiO₂ and bentonite drilling fluid containing PNA-SiO₂ were prepared by using deionized water. After ultrasonic dispersion for 15 min, samples were dropped onto the surface of an amorphous carbon film (3 mm, 200 mush), and the sample morphology was observed using a transmission electron microscope (Model JEOL JEM-F200, Japan).

3. Results and Discussion

3.1. Characterization of PNA-SiO₂

3.1.1. Response Temperature of PNA-SiO₂

3.1.1.1. FT-IR

Figure 4a,b shows the infrared spectrum and chemical structural formula of the polymer PNA-SiO₂, respectively. As shown in Figure 4a, methyl (−CH₃) and methylene (−CH₂) have stretching vibration peaks at 3064 and 2951 cm^–1, respectively. The presence of NIPAM monomers is indicated by the stretching vibration peaks of C–N and C=O in the amide group, which are the absorption peaks at 1467 and 1678 cm^–1. The peaks at 1357 and 1182 cm^–1 were the S=O stretching band of −SO₃H, while the one at 626 cm^–1 is the stretching vibration of C–S. For the KH570 modified Nano-SiO₂, the Si–OH generated by the hydrolysis of KH570 condenses with the SiO₂ surface to form Si–O–Si, corresponding to the bending vibration peak at 473 cm^–1. This demonstrated that Nano-SiO₂ exists.⁴³ Furthermore, the absence of the typical C=C absorption in the 1620–1645 cm^–1 region suggests that the monomers have undergone effective polymerization. According to the results, the copolymer was a grafted NIPAM/AMPS/Nano-SiO₂.

Figure 4.

Chemical structure characterization of PNA-SiO₂: (a) FT-IR curves; (b) chemical structural formula.

3.1.2. TGA

The TG and DTG curves of PNA-SiO₂ are displayed in Figure 5. There were three steps in the thermal weight loss process of PNA-SiO₂. During the first step (27–317 °C), the sample lost almost 11% of its weight. The amide bonds and other hydrophilic groups included in the polymer molecules cause the bound water to evaporate when heated. The volatilization concentrated within 160 °C, while the sample’s weight loss rate is only 1% at 160–317 °C. The second stage occurred at 317–432 °C. During this phase, the polymer’s quality rapidly declined at 327 and 400 °C, and the maximum decomposition rates were −1.236%/°C and −0.445%/°C, respectively. This was attributed to the side chains’ elimination of SO₂, SO₃, H₂O, and CO₂. The third stage was above 750 °C, during which the main chain of the polymer gradually decomposed. Consequently, PNA-SiO₂ can sustain a stable structure in geothermal drilling conditions, as evidenced by the sample retention rate of 89% and the initial decomposition temperature of the PNA-SiO₂ molecular chain of 317 °C.⁹

Figure 5.

TG and DTG curves of PNA-SiO₂.

3.2. Property Evaluation of PNA-SiO₂ Drilling Fluids: Effect of PNA-SiO₂ Concentration

Table 1 displays the rheology and filtration properties of 1–5% PNA-SiO₂ drilling fluid aged at 60 °C. The addition of 1% PNA-SiO₂ raised the drilling fluids’ AV from 4.5 to 45 mPa·s when compared to the basal mud. The PV increased from 3 to 27 mPa·s, the YP was enhanced from 1.533 to 18.396 Pa, and the gel strength increased by 167%. Compared with a reported rheological agent,⁴⁴ PNA-SiO₂ showed comparable efficacy in enhancing gel strength, as well as a superior capacity to improve the viscosity and YP and reduce fluid loss. PNA-SiO₂ is therefore a promising rheological agent that can transport rock powder and stabilize subterranean pressure variations. As the concentration of PNA-SiO₂ increased, the rheological parameters that characterize the viscosity and shear force of a drilling fluid continued to increase, and the filtration loss gradually decreased. The AV and PV values were higher than the six-speed viscometer’s measuring range when the PNA-SiO₂ addition was greater than 5%. Excessive dosage is challenging to pump and raises drilling expenses. Therefore, the evaluation of PNA-SiO₂ discussed in this paper was kept within a 5% range.

Table 1. Preliminary Evaluation of PNA-SiO₂ Drilling Fluid Properties.

formula	AV (mPa·s)	PV (mPa·s)	YP (Pa)	Gel10s (Pa)	Gel10 min (Pa)	FLAPI (mL)
65 °C, 4% rheological agent44	33	17	16	5	15	3.8
base mud	4.5	3	1.533	1.533	1.533	36
1% PNA-SiO2	45	27	18.396	2.555	4.088	7
2% PNA-SiO2	76	54	22.484	2.555	4.088	5
3% PNA-SiO2	105	66	39.858	3.577	5.11	4
4% PNA-SiO2	145	61	85.848	5.621	7.154	3
5% PNA-SiO2	147.5	40	109.865	11.242	12.264	2

3.3. Temperature Resistance of PNA-SiO₂ Drilling Fluids

Low-temperature geothermal resources (T ≤ 90 °C), medium-temperature geothermal resources (90 °C ≤ T < 150 °C), and high-temperature geothermal resources (T ≥ 150 °C) are all stored in formations with large geothermal gradients.⁴⁵ The hydration, swelling, and dispersibility of clay particles significantly declined when exposed to high temperatures, which led to the failure of rheological characteristics and an increase in filtration loss.⁴⁶ As a result, the temperature resistance of the PNA-SiO₂ drilling fluid is assessed across a broad temperature range (60–180 °C).

3.3.1. Optimal Selection of Rheological Models

The rheologic and hydraulic properties of drilling fluids can be described by the rheologic model. Proper understanding and application of rheological principles are vital in evaluating the drilling fluid behavior and in solving the problems of hole cleaning, hydraulic calculations, and cutting transport. The most widely used mathematical models are the formulas 7–10, which are described below.⁴⁷⁻⁴⁹ Origin software was used to fit the shear stress values measured by the viscometer into formulas 7–10, the rheological parameters were calculated for different models (τ₀, μ_p, τ_c, η_∞, K, n, etc.), and the goodness of fit (R²) values and root-mean-square error (RMSE) values were obtained. R² and RMSE are indicators for evaluating the fitting accuracy. The closer the R² value is to 1, the lower the RMSE value, indicating a higher fitting accuracy of the model. Therefore, based on parameters of R² and RMSE, the optimal model for describing the PNA-SiO₂ drilling fluid can be determined, and the rheological parameters under this model can be obtained (see Table 4).

7

8

9

10

where τ is shear stress, the unit is Pa; τ₀ is the yield point, the unit is Pa; μ_p is plastic viscosity, mPa·s; γ is shear rate, the unit is s^–1; η_∞ is the limiting high shear viscosity, the unit is mPa·s; K is the consistency index, the unit is Pa·sⁿ; τ_y is the yield point of the H–B model, the unit is Pa; and n is the flow behavior index, dimensionless parameter.

Table 4. Rheology Properties of PNA-SiO₂ Drilling Fluids Aged at Different Temperatures.

T (°C)	dosage of PNA-SiO2	YP/PV (Pa/mPa·s)	n	Gel10 s (Pa)	Gel10 min (Pa)
60	0	0.511	0.648	1.533	1.533
	1%	0.681	0.534	2.555	4.088
	2%	0.416	0.647	2.555	4.088
	3%	0.604	0.605	3.577	5.11
	4%	1.407	0.507	5.621	7.154
	5%	2.747	0.435	11.242	12.264
80	0	2.044	0.287	2.044	3.066
	1%	0.355	0.760	1.022	1.533
	2%	0.404	0.662	1.533	2.555
	3%	0.491	0.638	2.555	2.555
	4%	1.095	0.543	4.088	4.088
	5%	9.028	0.436	6.643	7.665
100	0	0.170	0.985	0.511	0.511
	1%	0.284	0.850	1.533	2.044
	2%	0.116	0.669	1.533	3.577
	3%	0.408	0.648	2.555	4.088
	4%	0.794	0.523	4.088	5.110
	5%	2.985	0.433	7.665	9.709
120	0	1.533	0.558	2.044	2.044
	1%	0.292	0.749	1.533	2.044
	2%	0.283	0.698	1.533	2.555
	3%	0.361	0.723	2.044	2.555
	4%	0.823	0.591	2.044	3.557
	5%	0.767	0.562	3.577	3.577
150	0	2.044	0.399	2.555	2.555
	1%	0.365	0.799	1.022	1.533
	2%	0.307	0.712	1.533	1.533
	3%	0.372	0.697	2.044	2.555
	4%	0.628	0.594	3.577	4.599
	5%	1.163	0.510	4.599	5.110
180	0	0.204	0.971	1.533	1.022
	1%	0.383	0.692	1.022	2.044
	2%	0.377	0.661	1.533	3.066
	3%	0.427	0.656	2.044	2.555
	4%	0.408	0.701	2.044	2.555
	5%	0.649	0.590	3.066	3.066

The rheological model fitting curves for 3% PNA-SiO₂ drilling fluids aged at 60–180 °C are displayed in Figure 6. As shown in Table 2, the R² values of the Bingham model, the Casson model, the power-law model (P–L model), and the Herschel–Bulkley model (H–B model) ranged from 0.950 to 0.973, 0.983 to 0.990, 0.997 to 0.9999, and 0.997 to 0.9998, respectively. The RMSE ranged from 5.376 to 8.314, 3.376 to 4.896, 0.489 to 1.656, and 0.573 to 1.677, respectively. Therefore, in defining the rheological properties of 3% PNA-SiO₂ drilling fluids at different aging temperatures, the P–L model and the H–B model exhibit comparably high accuracy, followed by the Casson model. The precision of the Bingham model is the lowest. This is because the rheological curve shifts from linear to nonlinear as a result of the drilling fluid being pseudoplastic due to the addition of polymers. After that, there was more discussion over the applicability of the P–L and H–B models for PNA-SiO₂ drilling fluids with varying concentrations. The H–B model’s R² value is consistently higher than or equal to the P–L model’s, as shown in Table 3. The polymer drilling fluid has a dynamic shear force, and the fluid will only begin to flow when the external force exceeds this value. The H–B model is a three-parameter model that modifies the P–L model by introducing dynamic shear force. Therefore, the H–B model is the optimal model with a higher accuracy in reflecting the rheology behavior of PNA-SiO₂ drilling fluids.

Figure 6.

Rheologic model fitting curves of PNA-SiO₂ drilling fluids: (a) Bingham model; (b) Casson model; (c) P–L model; and (d) H–B model.

Table 2. Goodness of Fit Parameters of Rheological Models.

rheologic model	Bingham		Casson		P–L		H–B
fitting parameters	R2	RMSE	R2	RMSE	R2	RMSE	R2	RMSE
60 °C – base mud	0.946	0.244	0.977	0.158	0.911	0.313	0.976	0.164
60 °C + 3% PNA-SiO2	0.950	8.287	0.983	4.858	0.998	1.435	0.998	1.475
80 °C – base mud	0.836	0.614	0.950	0.339	0.994	0.116	0.996	0.096
80 °C + 3% PNA-SiO2	0.956	8.314	0.985	4.896	0.999	1.360	0.999	1.401
100 °C – base mud	0.999	0.009	0.988	0.116	0.950	0.238	0.9999	0.006
100 °C + 3% PNA-SiO2	0.965	7.656	0.990	4.115	0.9999	0.489	0.9998	0.573
120 °C – base mud	0.942	0.263	0.998	0.051	0.943	0.261	0.999	0.031
120 °C + 3% PNA-SiO2	0.973	5.376	0.989	3.376	0.997	1.656	0.997	1.677
150 °C – base mud	0.887	0.438	0.981	0.180	0.977	0.197	0.998	0.061
150 °C + 3% PNA-SiO2	0.970	5.849	0.990	3.383	0.999	0.996	0.999	1.027
180 °C – base mud	0.990	0.167	0.974	0.271	0.894	0.550	0.990	0.165
180 °C + 3% PNA-SiO2	0.962	6.569	0.987	3.796	0.999	0.910	0.999	0.952

Table 3. Goodness of Fit Parameters of the Power-Law Model and the Herschel–Bulkley Model.

		R2
temperatures	dosage of PNA-SiO2	P–L	H–B
60 °C	1% PNA-SiO2	0.9998	0.9998
	2% PNA-SiO2	0.9999	0.9999
	3% PNA-SiO2	0.998	0.998
	4% PNA-SiO2	0.988	0.988
	5% PNA-SiO2	0.981	0.981
80 °C	1% PNA-SiO2	0.994	0.994
	2% PNA-SiO2	0.999	0.999
	3% PNA-SiO2	0.999	0.999
	4% PNA-SiO2	0.991	0.991
	5% PNA-SiO2	0.951	0.951
100 °C	1% PNA-SiO2	0.995	0.995
	2% PNA-SiO2	0.999	0.999
	3% PNA-SiO2	0.999	0.999
	4% PNA-SiO2	0.993	0.993
	5% PNA-SiO2	0.977	0.977
120 °C	1% PNA-SiO2	0.9995	0.9998
	2% PNA-SiO2	0.9999	0.9999
	3% PNA-SiO2	0.997	0.997
	4% PNA-SiO2	0.993	0.993
	5% PNA-SiO2	0.996	0.996
150 °C	1% PNA-SiO2	0.994	0.994
	2% PNA-SiO2	0.999	0.999
	3% PNA-SiO2	0.999	0.999
	4% PNA-SiO2	0.997	0.997
	5% PNA-SiO2	0.990	0.990
180 °C	1% PNA-SiO2	0.9995	0.9997
	2% PNA-SiO2	0.9997	0.9999
	3% PNA-SiO2	0.999	0.999
	4% PNA-SiO2	0.999	0.999
	5% PNA-SiO2	0.997	0.997

For base mud, the R² values of the Bingham model, the Casson model, the P–L model, and the H–B model ranged from 0.836 to 0.999, 0.950 to 0.998, 0.894 to 0.994, and 0.976 to 0.999, respectively. The RMSE ranged from 0.009 to 0.614, 0.051 to 0.339, 0.116 to 0.550, and 0.031 to 0.165, respectively. The H–B model has lower RMSE values and higher R² values. The addition of PNA did not have an effect on the rheological mode. The H–B model is also the most accurate rheological model for the base mud. Hence, the rheological parameter of the H–B model is calculated and discussed in Section 3.3.2 and Table 4.

3.3.2. Rheological Analysis of PNA-SiO₂ Drilling Fluids

As listed in Table 4 and Figure 7, the advantage of PNA-SiO₂ drilling fluid in high-temperature resistance is reflected in stable and sufficient rheological parameters. The higher the AV values, the higher the efficiency of carrying cuttings from the wellbore, which usually should be greater than 35 mPa·s. It is appropriate to maintain a flow pattern index (n) value of 0.4–0.8 and YP/PV above 0.36. The static shear force (Gel_10 min) characterizes the gel strength of the drilling fluid. Any clay-based drilling fluid should have a Gel_10 min of ≥3 lb/100 ft² (1.44 Pa) to provide sufficient force.⁵⁰ High temperature has an unacceptable negative impact on base mud. The base mud exhibits extremely low AV (3.5–6 mPa·s) at 60–180 °C. At 100–180 °C, there is a considerable risk of elevated pump pressure for base mud because the YP/PV ratio is as high as 1.533–2.044 Pa/mPa·s or is lower than 0.36.

Figure 7.

Effect of aging temperatures on the AV value of drilling fluids.

PNA-SiO₂ as a rheological agent effectively solves the problem of drilling fluids’ viscosity attenuation. At 60/80/100/120/150/180 °C, the addition of 1% PNA-SiO₂ achieved an AV increment of 10 times, 8.1 times, 16.4 times, 9 times, 7.9 times, and 4.6 times of the base mud, respectively. The AV value continues to increase as the PNA-SiO₂ dosage increases. The AV value of the fluid with ≥2% PNA-SiO₂ was always higher than 35 mPa·s. In addition, PNA-SiO₂ supports stable well pressure at high temperatures. Figure 7 shows that as the aging temperature increases from 60 to 180 °C, the AV values of the PNA-SiO₂ drilling fluid present an approximately straight line with fluctuations; there was no significant increase or decrease. It is worth mentioning that under the dual effects of high temperature and PNA-SiO₂, the bentonite in the base mud forms a bimodal particle size distribution curve at 100 °C (Figure 13b), and the presence of both coarse and fine clay particles in the system is considered to be the most favorable distribution for rheological properties.⁴¹ Hence, the AV value of 3% PNA-SiO₂ increases first and then decreases with the temperature increase, and shows a peak at 100 °C.

Figure 13.

Particle size distribution of the drilling fluid aged at different temperatures: (a) 60 °C, (b) 100 °C, (c) 150 °C, and (d) 180 °C.

The increase in temperature leads to fluctuations in YP/PV, an increase in the n value, and a reduction trend of Gel_10 min. Choosing the appropriate concentration of PNA-SiO₂ at a certain temperature can make it meet drilling requirements. At ≤80 °C, 2% PNA-SiO₂ is enough to provide a sufficient YP/PV ratio (0.404–0.416 Pa/mPa·s) and a suitable n value (0.662–0.647). At 100–180 °C, 3–4% is the preferred dosage of PNA-SiO₂. The YP/PV of the 3–4% PNA-SiO₂ drilling fluid is between 0.361 and 0.823, while the n value is controlled within the range of 0.523–0.723. Moreover, the Gel_10 min of 2–4% PNA-SiO₂ drilling fluids at 60–180 °C ranged from 1.533 to 7.154 Pa, which fully meets the force requirements. The value of Gel_10 min is always slightly higher than that of Gel_10 s, which indicates that the drilling fluid has good thixotropy. Therefore, when the circulation is stopped, the shear force of PNA-SiO₂ drilling fluids can rapidly increase to an appropriate value to suspend cuttings and ensure stable pump pressure.

In short, PNA-SiO₂ has a significant thickening effect and a positive impact on rheological parameters at 60–180 °C. With the increase of temperature, the decrease of AV and Gel_10 min, the increase of n value, and the fluctuation of YP/PV can be controlled within the required range by adjusting the PNA-SiO₂ concentration. A dosage of 2–4% PNA-SiO₂ is recommended. Analysis proves that PNA-SiO₂ is a rheological agent with good temperature resistance.

3.3.3. Filtration Property of PNA-SiO₂ Drilling Fluids

Filtration control is essential for safe drilling and reservoir protection since geothermal drilling frequently encounters leakage formations with highly developed holes or fissures.⁴⁶ The effects of PNA-SiO₂ and aging temperature on drilling fluid filtration properties are depicted in Figure 8.

Figure 8.

Filtration property of PNA-SiO₂ drilling fluids aged at different temperatures.

The bentonite in the drilling fluids is a type of montmorillonite clay, which begins to chemically break down at about 120 °C.⁵¹ The test results show that the fluid loss of bentonite base mud aged at 120/150/180 °C is as high as 30, 34, and 35 mL. This greatly increases the risk of differential sticking of the drill string. The addition of PNA-SiO₂ effectively controlled the poor leakage performance of the base mud. PNA-SiO₂ drilling fluid meets the API standard requirement of <15 mL by maintaining a minimal fluid loss (2–14 mL) within 180 °C.

Filtration loss can be further decreased by raising the PNA-SiO₂ content. In comparison to 1% PNA-SiO₂, the filtration volume of 5% PNA-SiO₂ dropped by 71.4, 75.0, 62.8, 47.8, and 57.1% at 60, 80, 100, 120, and 150 °C, respectively. At 180 °C, when the dosage of PNA-SiO₂ increased from 1 to 3% and 5%, the filtration volume decreased from 14 to 9.6 mL and 8.4 mL, respectively. As stated in 3.3.2, the AV rises with PNA-SiO₂ concentration. At 180 °C, the viscosity increased by 245 and 34% when the dosage of PNA-SiO₂ increased from 1 to 3% and 5%. According to the static filtration equation (formula 11), the filtration loss per unit permeable area is directly inversely proportional to the fluid viscosity.^38,52 Thus, raising the dosage of PNA-SiO₂ reduces the filtration volume by raising the fluid viscosity.

In short, PNA-SiO₂ can also serve as a fluid loss agent for geothermal drilling fluids, which is beneficial for reducing additive costs and improving environmental friendliness.

11

where dv/dt represents the filtration rate, K represents the cake permeability, A defines the cross-section area (63.6 cm²), ΔP defines the differential pressure (0.69 MPa), μ represents the viscosity, and h represents the mud cake thickness.

3.4. Salt Resistance of PNA-SiO₂

Geothermal reservoir fluids in some locations have extreme mineralization and are rich in Na⁺ and Cl^– ions after soluble minerals dissolve in the hot water. As reported, the highest mineralization rate of groundwater in the Chinese North Basin exceeds 8 g/L, and the hydro-chemical type is mainly Cl–Na.⁵³ Therefore, this study explored the influence of NaCl (150 °C, 5–36% NaCl) on the rheology and filtration properties of PNA-SiO₂ drilling fluids.

3.4.1. Rheology

Figure 9 displays the rheological characteristics of 3% PNA-SiO₂ drilling fluid with varying NaCl concentrations (0–36%) aged at 150 °C. PNA-SiO₂ fluids with different NaCl concentrations consistently had lower AV and PV values than the control group without NaCl. The AV value of 5% NaCl fluids decreased from 95.5 to 70 mPa·s, and the PV decreased from 70 to 52 mPa·s. 36% NaCl fluid exhibits the greatest viscosity change, and the maximum viscosity attenuation was controlled within 45%. As the dosage of NaCl gradually increased from 5 to 20%, both AV and PV values increased, and then it decreased with the continuous increase of NaCl. This is attributed to the dual effects of Na⁺ on the osmotic expansion of bentonite and on the electromotive potential, which will be explained in Section 3.5. Generally, adding NaCl reduced the viscosity of the PNA-SiO₂ drilling fluid, but within an acceptable range.

Figure 9.

Effect of NaCl on the rheology of 3% PNA-SiO₂ drilling fluid: (a) AV, (b) PV, (c) Gel_10 min, and (d) n value.

It is worth mentioning that the attenuation of viscosity does not affect the cutting-carrying performance of the PNA-SiO₂ drilling fluid as it exhibits good gel strength and flow behavior index. The Gel_10 min of 5% NaCl was 2.044 Pa, as shown in Figure 9c, which satisfies the minimum requirement for carrying cuttings (>1.44 MPa). The gel strength of the drilling fluid with 10–36% NaCl ranged from 4.088 to 5.110 Pa, higher than the control group (2.555 Pa). The n value of the PNA-SiO₂ drilling fluid with NaCl ranged from 0.700 to 0.752, consistently higher than that of the control group (n = 0.697). An improvement in cutting-carrying was demonstrated by a rise in the gel strength and n value. Therefore, NaCl and PNA-SiO₂ showed a synergistic effect on drilling fluids’ capacity to carry cuttings. This may be due to the hydration of NaCl weakening the hydrogen bonding between amide groups and water, the intermolecular association effect being enhanced, and a stable three-dimensional network structure being formed more easily in solutions.⁵⁴

In conclusion, PNA-SiO₂ consistently maintained sufficient viscosity and cutting-carrying capacity throughout a wide range of NaCl concentrations, making it an excellent flow pattern regulator for high-salinity geothermal reservoirs.

3.4.2. Filtration Property

The impact of NaCl on the filtration performance of 3% PNA-SiO₂ drilling fluid aged at 150 °C is depicted in Figure 10. The addition of NaCl decreased the dispersibility of bentonite to a certain extent, resulting in a decrease in the mud cake quality and an increase in filtration loss, as revealed in Section 3.5.3. However, as the concentration of NaCl increased from 5 to 36%, the filtration volume fully satisfied the API standard and varied within a comparatively low value of fluid losses (8.6–9.6 mL). As shown in Table 5, PNA-SiO₂ demonstrated a filtration control ability comparable to that of the current fluid loss agents. Therefore, PNA-SiO₂ has superior filtration reduction capabilities in geothermal reservoirs with high salinity.

Figure 10.

Effect of NaCl on the filtration volume of 3% PNA-SiO₂ drilling fluid.

Table 5. Comparison of Temperature and Salt Resistance between PNA-SiO₂ and Fluid Loss Agents.

fluid loss agents	experimental condition	FLAPI (mL)
3% PNA-SiO2	150 °C, 36% NaCl	8.8
1.5% modified chitosan (AMC)55	150 °C, 36% NaCl	20
graphene oxide acrylamide graft copolymer56	150 °C, 10% NaCl/36% NaCl	7.4/8.2
6% amphoteric ion fluid loss additive57	150 °C, 36% NaCl	<40
2% M-SiO2/ZMD58	30% NaCl	13.2

3.5. Function Mechanism between PNA-SiO₂ and Bentonite

3.5.1. XRD

It is commonly known that bentonite is composed of layered montmorillonite, and the interlayer spacing of montmorillonite determines its dispersibility. The base slurry’s hydration and dispersion improve with increasing interlayer spacing. Thus, the influence of PNA-SiO₂ and NaCl on the spacing of bentonite layers was characterized using XRD testing and eq 6. The following conclusions are summarized.

• 1)As the aging temperature rose, the interlayer spacing of bentonite reduced for both the base mud and PNA-SiO₂ drilling fluid because interlayer water vanished (Figure 11a–e). The bentonite interlayer spacing progressively shrank from 1.64 to 1.23 nm as the aging temperature rose from 60 to 180 °C.
• 2)The clay interlayer spacing in PNA-SiO₂ drilling fluid is nearly identical to that of the base mud after aging at various temperatures. Hence, the molecular structure of PNA-SiO₂ is relatively large and does not insert into the interlayer of clay.
• 3)Figure 11f shows that with the increased concentration of NaCl, the interlayer spacing of clay gradually increased. Compared with the control group, the interlayer spacing of bentonite in drilling fluids containing 10, 20, 30, and 36% NaCl increased by 19.7, 19.7, 21.3, and 30.7%, respectively. This is due to the fact that the addition of Na⁺ promotes the adsorption of water on the surface of clay crystals and the hydration of cations. The repulsive force between crystal layers is greater than the electrostatic attraction, which intensifies the permeability and expansion of clay, thereby improving the interlayer spacing and dispersibility of clay. This is the beneficial aspect of Na⁺.

Figure 11.

XRD curves of drilling fluid samples: (a) aged at 60 °C, (b) aged at 100 °C, (c) aged at 120 °C, (d) aged at 150 °C, and (e) aged at 180 °C, and (f) drilling fluids containing NaCl.

3.5.2. Zeta Potential Analysis

Drilling fluid is a stable colloidal system composed of bentonite particles. According to Stern’s diffusion double-layer theory, the larger the absolute value of the zeta potential (ξ or zeta potential), the higher the difference between the surface charge of clay particles and the counterion charge in the solvation layer. As the double-layer thickness increases, the colloidal system becomes more stable. The zeta potential analyzer is used to analyze the effects of temperature, PNA-SiO₂, and NaCl on the ξ of the drilling fluid.⁵⁹

Figure 12a shows that the zeta potential of the PNA-SiO₂ drilling fluid is always higher than that of the base mud. The PNA-SiO₂ molecular chain contains a large number of carboxyl groups (−COO) and sulfonic acid groups (−SO₃H), which are anionic groups with strong hydration characteristics, promoting the formation of solvent layers and reducing the number of charged charges, thereby improving colloidal stability. Meanwhile, as the aging temperature increased, the ξ of the drilling fluid first increased and then decreased. Temperature is a positive factor for raising the double layer’s thickness, as formula 11 illustrates. The absolute value of ξ increased gradually as the aging temperature rose from 60 to 120 °C, peaking at 120 °C. At temperatures above 150 °C, the hydration action was diminished and the functionalized groups of PNA-SiO₂ were inhibited. The absolute value of ξ began to decrease. This well explained the fluctuation law of the PNA-SiO₂ drilling fluid rheology.

Figure 12.

Zeta potential analysis: (a) influence of temperature and PNA-SiO₂, and (b) influence of NaCl.

Additionally, formula 12 demonstrates that the electrolyte concentration is a negative determinant for the double layer’s thickness. The quantity and thickness of ions in the diffusion layer decrease when Na⁺ is added because more counterions enter the adsorption layer. Thus, the addition of NaCl considerably decreased the zeta potential, as seen in Figure 12b. With the increase in NaCl concentration, the absolute value of the zeta potential continued to decrease, and the colloidal stability decreased.

12

where D represents the thickness of the double layer, and it is the reciprocal of Debye length; ε is a dielectric constant, the unit is C²/(N·m²); κ is the Boltzmann constant, the unit is J/K; T is temperature, the unit is K; n is the concentration of electrolyte, the unit is mol/L; Z is the ion valence number, dimensionless parameter; and e is the electronic charge, the unit is C.

3.5.3. PSA

A complex stratified flow regime for the transportation of multisize cuttings is created by the spatial inhomogeneity of fluid viscosity and particle sedimentation, which poses a safety risk underground. After being adequately hydrated in water, the bentonite breaks up into finer particles. A dense mud cake can be formed to control filtration, and good dispersibility efficiently inhibits agglomeration and sedimentation.⁶⁰ A laser particle size analyzer was used to determine the particle size of the base mud and PNA-SiO₂ drilling fluids, as seen in Figures 13–15. Table 6 contains a list of the parameters.

Figure 15.

PSA of PNA-SiO₂ drilling fluids with NaCl: (a) particle size distribution, and (b) cumulative distribution.

Table 6. Particle Size Parameters of Drilling Fluids.

temperature	sample	peak (μm)	D50 (μm)
60 °C	base mud	27.4	22.1
	3% PNA-SiO2	15.9	16.3
100 °C	base mud	35.2	28.2
	3% PNA-SiO2	17.4, 103.8	31.4
150 °C	base mud	60.9	44.9
	3% PNA-SiO2	30.8	28.9
180 °C	base mud	68.3	46.9
	3% PNA-SiO2	28.3	30.1
150 °C	10% NaCl	40.2	35.2
	20% NaCl	33.1	30.2
	30% NaCl	33.7	28.2
	36% NaCl	33.7, 89	37.5

As seen in Figure 13a–d, the peak of particle size was considerably decreased by the addition of PNA-SiO₂. In comparison to the base mud, the peak of the PNA-SiO₂ drilling fluid cured at 60, 100, 150, and 180 °C decreased by 42.0, 50.6, 49.4, and 58.6%, respectively. Specifically, a bimodal grading curve was observed in the PNA-SiO₂ drilling fluid at 100 °C, and fluids with coarse/fine particles exhibited better rheological properties. The same pattern is shown in Figure 14, the median particle size (D₅₀) of the fluid. The D₅₀ of the PNA-SiO₂ drilling fluid aged at 60, 150, and 180 °C was always lower than that of the base mud. After aging at 60–180 °C, the peak value and D₅₀ of the PNA-SiO₂ drilling fluid fluctuated within the ranges of 15.9–30.8 and 16.3–31.4 μm, while the peak and D₅₀ of base mud were 27.4–68.3 and 22.1–46.9 μm, respectively. Therefore, PNA-SiO₂ effectively enhanced the hydration and dispersion characteristics of bentonite, increased the content of fine particles, and maintained the stability of particles over a wide temperature range, which ensured the suspension capacity and filtration control.

Figure 14.

Cumulative distribution of the drilling fluid aged at different temperatures: (a) 60 °C, (b) 100 °C, (c) 150 °C, and (d) 180 °C.

The effects of NaCl concentrations on the particle size distribution and cumulative distribution of PNA-SiO₂ drilling fluid are depicted in Figure 15a,b. The dispersibility was prevented and the repulsion between the bentonite particles was decreased by the addition of Na⁺. The peak values of PNA-SiO₂ drilling fluids with 10, 20, 30, and 36% NaCl increased from 30.8 to 40.2, 33.1, 33.7, and 33.7 μm, respectively, in comparison to the control group without NaCl. The D₅₀ value also changed from 28.9 to 35.2, 30.2, 28.2, and 37.5 μm. Meanwhile, Na⁺ promoted interlayer swelling of montmorillonite, manifested as an increase in the fine particle content on the PSD curve. Therefore, the damaging effect of NaCl on bentonite dispersibility is limited, and the rheological and filtration properties of the PNA-SiO₂ drilling fluid under high mineralization conditions meet the API requirements.⁶¹

3.5.4. TEM

TEM was used to analyze the microstructure relationship between bentonite and PNA-SiO₂. Figure 16a,b shows the layered bentonite in the base mud. Figure 16c,d shows the PNA-SiO₂ drilling fluids at magnifications of ×8000 and ×12,000, respectively. It is evident that Nano-SiO₂ is evenly dispersed throughout the bentonite and works by adsorbing onto bentonite particles and constructing a network structure. Figure 16e–h shows the microstructure of PNA-SiO₂ aged at 60, 100, 150, and 180 °C. PNA-SiO₂ aged at 60 °C forms a weak network structure in solution, with some PNA-SiO₂ molecular chains exhibiting a linear distribution. The image’s dark block represents aggregated nano-SiO₂. By forming a stronger and denser network structure, PNA-SiO₂ guarantees the fluid’s stability and viscosity at higher aging temperatures. Meanwhile, the dispersion of nano-SiO₂ increases and is more distributed at the intersection nodes of the network structure.

Figure 16.

Images of TEM: (a, b) bentonite; (c) bentonite and PNA-SiO₂, ×8000; (d) bentonite and PNA-SiO₂, ×12,000; (e) PNA-SiO₂ aged at 60 °C; (f) PNA-SiO₂ aged at 100 °C; (g) PNA-SiO₂ aged at 150 °C; and (h) PNA-SiO₂ aged at 180 °C.

3.5.5. Mechanism Analysis

Based on the analyses of XRD, zeta potential, PSA, and TEM, the mechanism via which PNA-SiO₂ contributes to regulating flow patterns and reducing filtration loss can be summed up as follows.

As shown in Figure 17a, after aging at high temperatures (≤180 °C), PNA-SiO₂ did not intrude into the crystal interlayer and had almost no influence on the interlayer spacing of bentonite. However, it greatly boosted the repulsion between the colloidal particles, which improved the colloidal system’s stability and dispersibility. It is commonly known that for a constant concentration of slurry, the AV and PV values rise in tandem with the internal friction between the fluid layer and/or solid particles as the dispersibility of bentonite increases.⁶² On the other hand, the molecular chain of PNA-SiO₂ provides a large number of amide groups (−CONH) and hydroxyl groups (−OH). The former has a strong adsorption capacity but low thermal stability, while the latter has a limited adsorption capacity but strong resistance to temperature and salt. When combined, they guarantee that PNA-SiO₂ can adsorb onto bentonite particles at high temperatures and exert its effect. There are more linear polymer molecules in the PNA-SiO₂ solution at lower ambient temperatures. PNA-SiO₂ changes into a network structure as the temperature rises, and Nano-SiO₂ offers enough stability for network intersections to offset the detrimental effects of rising temperatures on the fluid’s friction and viscosity. Consequently, at higher temperatures, PNA-SiO₂ exhibits superior gel strength properties, such as adequate dynamic and static shear force values. In short, the PNA-SiO₂ drilling fluid exhibited stable rheological properties and filtration control ability by constructing a stable thixotropic network and forming high-quality mud cakes.

Figure 17.

Schematic diagram of mechanism analysis.

As shown in Figure 17b, the salt tolerance of PNA-SiO₂ is the result of a game of two factors. On the one hand, XRD and PSD analyses have shown that Na⁺ promotes the permeation expansion between crystal layers, improves the dispersibility of bentonite, increases the content of fine particles in the system, and optimizes the particle size distribution of the colloidal system. Internal friction in the system is increased by fine particles with a higher specific surface area, and the AV or PV values of the NaCl drilling fluid initially rise as a result. On the other hand, Na⁺ results in a decrease in the diffusion double layer’s thickness, a reduction in colloidal stability, and a stronger tendency for bentonite aggregation, which is shown by an increase in peak and median particle sizes. When the influence of the latter exceeds that of the former (NaCl > 20%), the viscosity value of the PNA-SiO₂ drilling fluid continues to decrease with the increase of NaCl. Overall, the PNA-SiO₂ drilling fluid consistently meets the requirements of API in the NaCl system.

4. Conclusions

In this study, a rheological agent, PNA-SiO₂, for high-temperature and high-salt geothermal drilling was designed and synthesized. The H–B model is a preferred model for describing the rheological behavior of PNA-SiO₂-based drilling fluids in geothermal reservoir environments. Strong adsorption, the formation of a stable thixotropic network structure, and the strengthening of repulsion between colloidal particles are the mechanisms by which PNA-SiO₂ contributes to the regulation of rheology and filtration. After aging at 60–180 °C, rheological investigation demonstrates that 2–4% PNA-SiO₂ has an excellent ability to improve the viscosity and enhance the shear force while retaining adequate rheological parameters (Gel_10 min ≥ 1.533 Pa). PNA-SiO₂ exhibits excellent filtration control ability (FL_API ≤ 9.6 mL), fully meeting the API requirements without the need for additional fluid loss agents. After aging at 150 °C, PNA-SiO₂ consistently maintained sufficient viscosity (AV ≥ 55 mPa·s, PV ≥ 44 mPa·s) and low filtration volume (8.6–9.6 mL) throughout a wide range of NaCl concentrations (5–36%), making it a rheological agent for high-salinity geothermal reservoirs. The salt tolerance of PNA-SiO₂ is the result of a game between the positive effect of Na⁺ on the layer spacing of bentonite and the negative effect on the thickness of the diffusion double layer.

This study provides a solution to the issue of downhole pressure fluctuations caused by rheological attenuation in severe drilling environments. Next, industrialized monomers and reagents will be used to expand the synthesis ratio of PNA-SiO₂ and explore its large-scale production.

Glossary

Abbreviations

TSP

temperature-sensitive copolymer

T_m

responding temperature

NIPAM

N-isopropylacrylamide

AMPS

2-acrylamido-2-methyl-1-propanesulfonic acid

AV

apparent viscosity

PV

plastic viscosity

YP

yield point

Gel_10s

initial gel strength

Gel_10 min

final gel strength

FT-IR

Fourier transform infrared

TGA

thermal gravity analysis

XRD

X-ray diffraction

PSA

particle size analysis

TEM

transmission electron microscopy

API

The American Petroleum Institute

P–L model

power-law model

H–B model

Herschel–Bulkley model

RMSE

root-mean-square error

K

consistency index

n

flow behavior index

D₅₀

median particle size

The authors declare no competing financial interest.