Composite Effect of Nanoparticles and Conventional Additives on Hydrate Formation in Seawater-Based Drilling Fluids

Abstract

The design of high-performance drilling fluid systems is of vital importance for the safe and efficient exploitation of natural gas hydrates. Incorporating appropriate nanoparticles into drilling fluids can significantly enhance drilling fluid loss control, wellbore stability, and hydrate inhibition. However, the combined effects of nanoparticles and conventional additives on hydrate inhibition in drilling fluid systems remain poorly understood. In this study, the influence of nanoparticles on hydrate formation was first evaluated in a base mud, followed by an investigation of their combined effects with common drilling fluid additives. The results demonstrate that hydrophilic nano-CaCO₃ particles exhibit hydrate inhibitory effects, with the strongest inhibition observed at 3.0%. Composite system tests (incorporating nanoparticles with sepiolite, filtrate reducers, and flow modifiers) revealed diverse effects on hydrate formation. Specifically, the combination of nanoparticles and sepiolite promoted hydrate formation; the combination of nanoparticles and filtrate reducers showed divergent effects. Mixtures of nanoparticles with 0.2% low-viscosity anionic cellulose (LV-PAC), carboxymethyl starch (CMS), and low-viscosity carboxymethyl cellulose (LV-CMC) inhibited hydrate formation, while mixtures with 0.2% sulfonated phenolic resin (SMP-2) and hydrolyzed ammonium polyacrylonitrile (NH₄-HPAN) accelerated hydrate formation. Notably, the incorporation of nanoparticles with 0.3% guar gum, sesbania gum, high-viscosity carboxymethyl cellulose (HV-CMC), or high-viscosity polyanionic cellulose (HV-PAC) resulted in the complete inhibition of hydrate formation. By contrast, the synergistic inhibition effect of the nanoparticle/xanthan gum (XC) composite system was relatively weak, with the optimal compounding concentration determined to be 0.3%. These findings provide critical insights for the development of drilling fluid systems in natural gas hydrate reservoirs, facilitating the optimization of drilling performance and enhancing operational safety in hydrate-bearing formations.

1. Introduction

Natural gas hydrates (NGHs), primarily composed of methane hydrates, are ice-like crystalline compounds formed by the molecular encapsulation of methane gas within water molecules under specific low-temperature and high-pressure conditions [1]. Characterized by high energy density and low environmental footprint, NGHs represent a novel class of clean energy resources with remarkable combustion efficiency [2]. Thermodynamic analyses show that 1 m³ of hydrate dissociation yields 164 m³ of methane gas and 0.8 m³ of water under standard conditions [3]. Global hydrate reserves are estimated at 10¹⁵–10¹⁸ m³, corresponding to approximately 2 × 10¹⁵ metric tons of oil equivalent [4]. This enormous energy potential exceeds twice the carbon content stored in all conventional fossil fuel reserves combined. These exceptional properties have established NGHs as a strategic alternative to traditional hydrocarbons, prompting significant research investments from governments, energy industries, and academic institutions worldwide [5]. China’s formal classification of hydrates as the 173rd mineral resource has marked a pivotal milestone in commercial exploitation technologies [6].

Hydrate exploration and development are inherently dependent on drilling operations. However, hydrate drilling presents well integrity challenges, including massive hydrate plugging within wellbores and well-wall destabilization caused by hydrate decomposition/regeneration cycles [7]. These issues primarily stem from drilling fluid invasion into hydrate-bearing formations, which disrupts the pressure–temperature equilibrium required for hydrate stability [8]. Furthermore, since NGHs are mainly concentrated in marine sediments on the seafloor, their drilling and production operations must face the challenging deepwater environment characterized by low temperature and high-pressure conditions. These operating environments are particularly vulnerable to secondary hydrate formation caused by shallow gas invasion or gas release during hydrate decomposition [9].

The development of optimized drilling fluid formulations represents a critical solution pathway. Superior fluid-loss control minimizes filtrate invasion, inhibits shale hydration and swelling, and facilitates the formation of thin, impermeable filter cakes to preserve reservoir integrity. The incorporation of nanoparticles into drilling fluids has been demonstrated to significantly enhance their anti-filtration and plugging performance in porous and fractured formations [10,11]. This approach is particularly promising for gas hydrate reservoirs, which are often characterized by low-permeability, fine-grained sediments [12]. Despite its potential, the application of nanoparticle-based drilling fluids in hydrate-bearing formations has not yet been reported. This absence may be attributed to the limited number of hydrate drilling campaigns conducted thus far, as well as concerns about the potential for hydrate formation around nanoparticles to obstruct fluid flow pathways [13,14].

Numerous studies have demonstrated that hydrophobic nanoparticles can facilitate gas hydrate formation by adsorbing gas molecules onto their surfaces, thereby enhancing the local structuring of water molecules to form hydrate cages [15]. In contrast, certain concentrations of hydrophilic nanoparticles, such as nano-CaCO₃ and nano-SiO₂, have been reported to inhibit hydrate formation [11,16,17]. In light of the critical importance of environmental protection in offshore drilling operations and the necessity of preserving reservoir integrity, hydrophilic nano-CaCO₃ has been selected as the nanoparticle additive for this study. It is important to note that drilling fluid is a complex system comprising multiple conventional additives, including sepiolite [18], polymers [14,19], filtrate reducers [20,21], and flow modifiers [22]. While the influence of individual additives on gas hydrate formation has been the subject of extensive research, the synergistic or antagonistic effects resulting from the combination of nanoparticles and conventional drilling fluid additives on hydrate formation kinetics remain largely uninvestigated.

Therefore, this investigation systematically examines the synergistic effects of nanoparticles combined with conventional additives—including sepiolite, filtrate reducers, and flow modifiers—on natural gas hydrate formation. A simulated seawater solution was prepared using ultrapure water containing 3.5% NaCl, excluding other ionic species. Commercially sourced additives, specifically LV-PAC (low-viscosity anionic cellulose), CMS (carboxymethyl starch), LV-CMC (low-viscosity carboxymethyl cellulose), SMP-2 (sulfonated phenolic resin), and NH₄-HPAN (hydrolyzed ammonium polyacrylonitrile), were selected as filtrate reducers. Guar gum, tara gum, HV-CMC, HV-PAC, and Xanthan gum (XC) were employed as flow modifiers due to their recognized properties of robust inhibitory performance, optimal rheological behavior, and compatibility with aqueous systems. Experimental trials were conducted under controlled thermodynamic conditions (3.0 °C, 6.0 MPa) to quantify key hydrate formation parameters—induction time, cumulative methane consumption, and average methane uptake rate—across composite systems incorporating nano-CaCO₃ and conventional additives. Subsequent analysis elucidated synergistic or antagonistic interactions between these compounds in modulating hydrate crystallization kinetics.

2. Experimental Section

2.1. Materials

Hydrophilic CaCO₃ particles with an average particle size of 20 nm were prepared by Specialty Minerals Inc. (New York, NY, USA). Figure 1 presents scanning electron microscopy (SEM) images of the hydrophilic nano-CaCO₃ particles employed in this study. The comprehensive characterization of these particles, including wettability analysis, surface functional group identification, and dispersion behavior evaluation, was previously reported in our earlier work [12]. Other experimental materials included distilled water (prepared in the laboratory); clay sepiolite; filtrate reducers: low-viscosity anionic cellulose (LV-PAC), carboxymethyl starch (CMS), low-viscosity carboxymethyl cellulose (LV-CMC), sulfonated phenolic resin (SMP-2), and hydrolyzed ammonium polyacrylonitrile (NH₄-HPAN); flow modifiers: guar gum, sesbania gum, xanthan gum (XC), high-viscosity carboxymethyl cellulose (HV-CMC), and high-viscosity polyanionic cellulose (HV-PAC); and high-purity N₂ and CH₄ gas with a purity of >99.9% (Wuhan Nuruide Special Gases Co., Ltd., Wuhan, China).

2.2. Experimental Setup

The experiments were conducted using a custom-built multifunctional hydrate reaction simulation system (Figure 2), with the key technical specifications detailed in

Table 1. Main technical parameters of the HCSHW-1 multifunctional hydrate reaction simulation device.

Working Environment	Temperature (°C)	0~60
	Humidity	≤80% RH
Working status	power supply (V)	220
	Temperature (°C)	−30~40
	Pressure (MPa)	≤20
Sensors are equipped and accurate	Temperature sensor	2	Measure Accuracy	0.03 °C
	Pressure sensors	1		0.005 MPa
Flowmeter equipment and accuracy	Ordinary flow meter	1		1.0% F.S
	Wet flow meter	1

. The apparatus comprises four integrated subsystems: a high-pressure reactor vessel, a cryogenic circulation unit, a gas pressurization system, and a data acquisition module. The core component is the cylindrical reactor (internal volume 500 mL) constructed from stainless steel, designed to withstand operational pressures up to 20 MPa with a temperature regulation range of −30 to 40 °C. Temperature control is achieved through a DLSB-20 recirculating chiller (accuracy ±0.1 °C) connected to a jacketed thermal bath. This cryogenic system maintains the reactor at 3.0 ± 0.2 °C throughout hydrate formation processes. The system underwent thermal equilibration prior to pressurization. High-purity methane (99.999% research grade) was then introduced into the reaction vessel using a dual-stage gas booster pump. System pressure was precisely regulated to the target value of 6.0 MPa, with real-time monitoring provided by a Druck PTX1400 pressure transducer (accuracy ±0.05 MPa). The data acquisition system simultaneously records temperature (T-type thermocouples, ±0.1 °C) and pressure measurements at 15 s sampling intervals, ensuring a temporal resolution sufficient for nucleation detection.

2.3. Experimental Procedure

The experimental steps of the multifunctional hydrate reactor are as follows: (1) the reactor is cleaned with ultrapure water, and the reactor is cleaned 3 times in total; (2) use nitrogen to check the air tightness of the reactor to ensure the safety of the experiment; (3) draw 300 mL of sample into the reactor; (4) inject methane into the buffer tank to make the pressure in the buffer tank reach 10.0 MPa; (5) adjust the water bath cooling system and set the target temperature; (6) turn on the mechanical stirring device and set the speed to 800 rpm; (7) after the temperature reaches 3.0 °C, the pressure of the reactor is increased to 6.0 MPa; (8) turn on the monitoring system to record the changes in temperature and pressure in the reactor during the experiment; (9) each experiment should be repeated at least three times to ensure the accuracy and reproducibility of the experimental results.

2.4. Data Processing

Figure 3 shows the temperature–pressure variation curves during hydrate reaction in (a) base mud (artificial seawater and 2% sepiolite) and (b) nano-CaCO₃ + base mud. The induction time of methane hydrate formation in base mud or base mud with added CaCO₃ can be directly read from Figure 3a,b, i.e., the hydrate formation process exhibited distinct initiation and termination time points. The initial hydrate nucleation occurred at t₁ = 67.35 min and 81.5 min, while the completion of hydrate formation was recorded at t₂ = 1152.40 min and 1205.47 min. Corresponding pressure measurements revealed a significant pressure drop during this crystallization period: the reactor pressure decreased from P₁ = 5.751 MPa and 5.770 MPa at the onset of hydrate formation to P₂ = 4.621 MPa and 4.835 MPa upon process termination. This 19.6% and 16.2% pressure reduction (ΔP = 1.13 MPa and 0.935 MPa) demonstrates substantial gas consumption during the hydrate crystallization phase. The gas used in the experiments in this study is methane, so the amount of hydrate formation can be expressed by CH₄ consumption, which is calculated as [23]:

$$\mathsf{\Delta }n=({\displaystyle \frac{P_1}{Z_1}}-{\displaystyle \frac{P_2}{Z_2}})\cdot {\displaystyle \frac{V}{RT}}$$

(1)

where $\mathsf{\Delta }$n is the total consumption of CH₄ in mol; R is the gas constant, about 8.31441 J/(mol·K); T is the temperature of the gas, K; v is the volume of gas, m³; and Z₁ and Z₂ are the gas compression factors in the P₁ and P₂ states, respectively.

Based on the relationship between the amount of formation and the rate of formation, the rate of hydrate formation can be deduced as follows:

$$v={\displaystyle \frac{∆n}{\left(t_2-t_1\right)}}$$

(2)

where v is the average gas consumption rate, mol/min.

3. Results and Discussion

3.1. Effect of Nanoparticles in the Base Mud

According to the previous research results [12], hydrophilic 20 nm CaCO₃ nanoparticles were incorporated into the base mud composed of artificial seawater and 2% sepiolite at varying concentrations to systematically investigate their effects on hydrate formation kinetics. The corresponding experimental results for each test group are presented in

Table 2. The experimental data obtained from the experiments of base mud + nano-CaCO₃ at different concentrations in each group.

Sample	The Amount Added (%)	t1 (min)	t2 (min)	P1 (MPa)	P2 (MPa)
Base mud + CaCO3	0%	67.35	1152.40	5.751	4.621
	1.0	62.73	1170.69	5.768	4.795
	2.0	71.27	1187.32	5.746	4.753
	3.0	81.50	1205.47	5.770	4.835
	4.0	74.85	1153.68	5.735	4.811
	5.0	71.48	1109.65	5.722	4.826

Note: “base mud” is composed of artificial seawater and 2% sepiolite.

.

According to the red dashed lines in Figure 4, the induction periods of hydrate formation for each experimental group were determined. Compared with the hydrate formation in the base mud, the induction period was shortened after adding 1.0% hydrophilic 20 nm CaCO₃ particles. This is because nano-CaCO₃ has a high specific surface area and surface energy drive, which can reduce the nucleation activation energy and increase the nucleation sites (Figure 5a) [16]. However, when the loading of hydrophilic 20 nm CaCO₃ particles increased to 2.0% and 3.0%, the induction periods of hydrate formation were prolonged, both exceeding those in the base mud, indicating that the nanoparticles exhibited an inhibitory effect on hydrate nucleation. The hydroxyl groups (-OH) on the surface of nano-CaCO₃ can adsorb water molecules through hydrogen bonding, forming multiple layers of bound hydration layers. The thickness of the bound hydrated layer formed can reach 5–10 nm. Such adsorbed water molecules are bound by the hydrogen bond network, and their translational and rotational degrees of freedom are significantly reduced, making it difficult for them to detach from the particle surface and participate in the assembly of the hydrate cage-like structure. At this point, the effective concentration of free water molecules in the solution (i.e., the free water molecules that have not been adsorbed) can be reduced by 20% to 30%, resulting in a limited “raw material supply” for the growth of hydrates (Figure 5) [17]. At nanoparticle concentrations ranging from 4.0 to 5.0%, although the corresponding hydrate induction periods remained prolonged, their capacity to delay hydrate formation weakened compared to the 3.0 wt% concentration. By using Equations (1) and (2), the CH₄ hydrate formation quantity and rate for each experimental group were calculated, and the results are visualized in Figure 4.

The green bars in Figure 4 illustrate the hydrate formation quantities for each experimental group. Quantitative analysis demonstrates that increasing the loading of hydrophilic 20 nm CaCO₃ nanoparticles leads to a gradual reduction in CH₄ hydrate formation within the drilling fluid, with the minimum formation quantity observed at a nanoparticle concentration of 5.0%. This suggests that hydrophilic 20 nm CaCO₃ inhibits hydrate formation, and its inhibitory efficacy enhances with increasing concentration.

The cyan bars in Figure 4, representing the CH₄ hydrate formation rate, indicate that increasing the nanoparticle concentration from 1.0 to 3.0% systematically decreases the formation rate, implying strengthened inhibition of hydrate kinetics within this concentration range. At higher concentrations (4.0–5.0%), the formation rate remains lower than that of the base mud but exhibits weakened inhibition compared to the 3.0% case, suggesting a concentration-dependent decline in inhibitory efficacy beyond 3.0%.

In summary, hydrophilic 20 nm CaCO₃ effectively inhibits CH₄ hydrate formation. The optimal inhibitory performance is achieved at 3.0 wt%, where the induction period is prolonged by 21.01%, the formation quantity is reduced by 16.59%, and the formation rate is decreased by 19.51% relative to the base fluid. These results validate the selection of 3.0% hydrophilic 20 nm CaCO₃ in the drilling fluid formulation.

3.2. Effect of Nanoparticles and Additives on Hydrate Formation

The objective of this study was to investigate the composite effects of 3.0% hydrophilic 20 nm CaCO₃ nanoparticles with sepiolite, filtrate reducers, and flow modifiers on the hydrate inhibition capacity.

3.2.1. Sepiolite—Nanoparticle Composite Effect

The composite effects of pulping clay (sepiolite) and 20 nm hydrophilic CaCO₃ on hydrate formation were investigated, and the experimental data are presented in

Table 3. The experimental data obtained by combining 3% CaCO₃ with sepiolite at different concentrations.

Sample Measurement	t1 (min)	t2 (min)	P1 (MPa)	P2 (MPa)
3.0%CaCO3	74.85	1197.42	5.748	4.022
3.0%CaCO3 + 1.0%sepiolite	26.88	1401.65	5.777	3.785
3.0%CaCO3 + 2.0%sepiolite	47.82	1284.50	5.602	3.852
3.0%CaCO3 + 3.0%sepiolite	44.18	1278.36	5.657	3.846
3.0%CaCO3 + 4.0%sepiolite	32.73	1351.72	5.688	3.830

.

The experimental data in Table 3 were employed to calculate the hydrate formation quantity and rate using Equations (1) and (2), with the computational results documented in Figure 6a. The induction periods for each experimental group were derived from the red dashed lines in Figure 6a. Analysis of the hydrate induction periods indicated that the addition of sepiolite to the CaCO₃ solution notably shortened the induction period, suggesting that sepiolite promoted hydrate nucleation. Sepiolite promotes the growth of methane hydrates through multiple mechanisms, including providing nucleation sites through nano-pores with a high specific surface area, promoting the directional arrangement of molecules through surface hydroxyl adsorption, optimizing mass transfer through interface effects, and stabilizing the structure through ionic electrostatic interaction [24]. The composite of sepiolite and nano-calcium carbonate significantly enhances the growth kinetics of methane hydrates and the stability of crystal structures through the construction of dual-scale nucleation sites, the optimization of mass transfer pathways, and synergistic stabilization at the interface (Figure 5) [17]. However, with the increase in sepiolite concentration, the induction period of hydrate formation first prolonged and then shortened, exhibiting no clear regularity, which merits further investigation.

The bar charts in Figure 6a depict divergent trends in hydrate formation quantity and rate following the addition of varying sepiolite concentrations to a 3% CaCO₃ solution. Compared with the 3% CaCO₃ system, all sepiolite-modified groups exhibited enhanced hydrate formation quantities, providing evidence that sepiolite promotes hydrate accumulation. However, no systematic correlation was found between sepiolite dosage and formation quantity. In terms of another kinetic parameter, the addition of sepiolite universally reduced the hydrate formation rate relative to the 3% CaCO₃ baseline, suggesting an inhibitory effect on hydrate growth. The rate profile displayed a non-monotonic trend of initial decrease, subsequent increase, and then decrease again with increasing sepiolite concentration. Notably, the 2.0% sepiolite group showed the lowest formation quantity, with a formation rate second only to that of the 4.0% sepiolite group.

In conclusion, although no clear concentration-dependent pattern was observed for the hydrate formation parameters with increasing sepiolite content, the addition of sepiolite to 3% CaCO₃ solutions consistently shortened the induction period, increased the formation quantity, and reduced the formation rate. The weakest promoting effect on hydrate formation was observed at a sepiolite concentration of 2.0%, which was characterized by the lowest formation quantity and suboptimal growth kinetics.

3.2.2. Nanoparticles—Filtrate Reducers Composite Effect

By reviewing the relevant research literature on filtrate reducers [14,19,20,21], the conventional performance of several common filtrate reducers was compared, and five filtrate reducers were selected as deflocculants for drilling fluid formulations. This section focuses on investigating the effects of these defilators on hydrates after compounding with nano-CaCO₃. The experimental results are presented in

Table 4. The experimental data were obtained by combining 3% CaCO₃ with five types of filtrate reducers.

Sample Measurement	t1 (min)	t2 (min)	P1 (MPa)	P2 (MPa)
3.0%CaCO3	74.85	1197.42	5.748	4.022
3.0%CaCO3 + 0.2%LV-PAC	137.92	1384.66	5.742	3.893
3.0%CaCO3 + 0.2%CMS	146.12	1389.90	5.735	3.843
3.0%CaCO3 + 0.2%LV-CMC	122.26	1390.53	5.765	3.905
3.0%CaCO3 + 0.2%SMP-2	32.45	761.75	5.724	3.666
3.0%CaCO3 + 0.2%NH4-HPAN	35.57	1446.75	5.775	3.898

.

Based on the experimental data in Table 4 and by Equations (1) and (2), the amount of hydrate formation and the rate of formation can be calculated, and the results are shown in Figure 6b.

As shown by the red curve in Figure 6b, compared with CH₄ hydrate formation in a 3% CaCO₃ solution, the addition of 0.2% different filtrate reducers exerted distinct effects on the induction time. The inclusion of LV-PAC, CMS, and LV-CMC significantly prolonged the induction time by 84.26%, 95.22%, and 63.34%, respectively. This indicates that these three filtrate reducers effectively delayed hydrate nucleation, with their efficacy in prolonging the induction time ranked as CMS > LV-PAC > LV-CMC. In contrast, adding 0.2% SMP-2 or 0.2% NH₄-HPAN to the 3% CaCO₃ solution notably shortened the CH₄ hydrate induction time, suggesting that both SMP-2 and NH₄-HPAN promote hydrate nucleation, with SMP-2 exhibiting a more pronounced promoting effect than NH₄-HPAN.

As shown by the yellow histogram in Figure 6b, for hydrate formation rates, the addition of 0.2% LV-PAC, CMS, LV-CMC, or NH₄-HPAN to a 3% CaCO₃ solution resulted in decreased hydrate formation rates across all experimental groups. The regulatory effect of filter reducers on the growth of methane hydrates is the result of the synergy of multiple mechanisms such as surface adsorption, interfacial energy regulation, mass transfer optimization, and ionic interaction. Inhibitory filter reducers (such as cellulose-based and nanocomposite systems) compounded with nano-CaCO₃ achieve inhibitory effects by reducing interinterface energy, hindering mass transfer, and competing for free water molecules (Figure 7d) [17]. This indicates that these four filtrate reducers effectively retarded CH₄ hydrate growth, with their retardation efficacy ranked as NH₄-HPAN > LV-CMC > LV-PAC > CMS. In contrast, the addition of 0.2% SMP-2 significantly increased both the hydrate formation quantity and rate compared to the 3% CaCO₃ solution, demonstrating the SMP-2-promoting effect on hydrate formation. Promoting filter reducers (such as surfactants and nanoparticles) compounded with nano-CaCO₃ accelerate hydrate formation by reducing interfacial tension, providing nucleation sites, and solubilizing gases (Figure 7d) [24]. These findings reveal that among the five filtrate reducers investigated, four (NH₄-HPAN, LV-CMC, LV-PAC, and CMS) exhibit hydrate formation retardation properties, whereas SMP-2 conversely accelerates hydrate formation with a significant enhancement of 82%. The experimental results further show that adding 0.2% LV-PAC, CMS, LV-CMC, or NH₄-HPAN to the 3% CaCO₃ solution increased CH₄ hydrate formation quantity while reducing the formation rate. In contrast, the inclusion of 0.2% SMP-2 not only enhanced the hydrate formation quantity but also markedly accelerated the formation rate.

To further investigate the composite effects, five concentration gradients (0.1%, 0.2%, 0.3%, 0.4%, and 0.5%) of LV-PAC and NH₄-HPAN were systematically added to a 3% CaCO₃ solution based on the above inhibitory evaluation results, and the kinetic parameters of hydrate formation were obtained. The corresponding experimental data are summarized in

Table 5. Experimental data (parameters of the hydrate formation process) obtained by combining 3% CaCO₃ with different concentrations of LV-PAC.

Sample Measurement	t1 (min)	t2 (min)	P1 (MPa)	P2 (MPa)
3%CaCO3	74.85	1197.42	5.747	4.022
3%CaCO3 + 0.2%LV-PAC	137.92	1384.66	5.742	3.893
3%CaCO3 + 0.4%LV-PAC	176.52	1427.70	5.746	4.230
3%CaCO3 + 0.6%LV-PAC	260.37	1412.38	5.837	5.157
3%CaCO3 + 0.8%LV-PAC	400.43	1370.30	5.831	5.177
3%CaCO3 + 1.0%LV-PAC	426.81	1315.75	5.735	5.387

and

Table 6. Experimental data (parameters of the hydrate formation process) for 3% CaCO₃ compounded with different concentrations of NH₄-HPAN.

Sample Measurement	t1 (min)	t2(min)	P1 (MPa)	P2 (MPa)
3%CaCO3	74.85	1197.42	5.748	4.022
3%CaCO3 + 0.5%NH4-HPAN	31.18	1184.56	5.759	3.758
3%CaCO3 + 1.0%NH4-HPAN	32.28	1218.20	5.715	3.806
3%CaCO3 + 1.5%NH4-HPAN	31.20	1035.80	5.733	3.935
3%CaCO3 + 2.0%NH4-HPAN	30.22	1039.95	5.718	3.947
3%CaCO3 + 2.5%NH4-HPAN	33.56	1126.72	5.729	3.924

.

From the experimental data in Table 5 and Table 6, the hydrate formation quantity and rate for each experimental group were calculated using Equations (1) and (2), with the results presented in Figure 6c,d.

As shown in Figure 6c, the addition of 0.2% LV-PAC prolonged the induction time of CH₄ hydrate formation, reduced the hydrate formation rate, and increased the hydrate formation quantity compared to the 3% CaCO₃ solution. With the LV-PAC concentration increasing from 0.2% to 0.6%, the induction time was progressively extended, and both the hydrate formation quantity and rate exhibited a gradual decline, suggesting an enhanced inhibitory effect on hydrate formation. However, when the LV-PAC concentration increased from 0.6% to 0.8%, no notable further reductions in formation quantity or rate were observed, indicating minimal enhancement in inhibition capability within this range. At an LV-PAC concentration of 1.0%, the induction time reached 426.81 min, accompanied by a hydrate formation quantity of 0.07 mol and an average formation rate of 0.078 × 10⁻³ mol/min. Compared to the 3% CaCO₃ solution, these values correspond to a 470.22% extension in induction time, a 79.17% reduction in hydrate quantity, and a 73.91% decrease in formation rate, confirming the pronounced inhibitory effect of 1.0% LV-PAC. A comprehensive analysis indicates that the hydrate inhibition capability of LV-PAC strengthens progressively with increasing concentrations.

As shown by the blue curve in Figure 6d, the induction time of hydrate formation in each experimental group was significantly shortened after the addition of NH₄-HPAN, indicating that NH₄-HPAN can shorten the hydrate induction time and promote hydrate nucleation. As demonstrated in Figure 6d, adding varying concentrations of NH₄-HPAN to a 3% CaCO₃ solution resulted in increased hydrate formation quantities and accelerated formation rates across all experimental groups. This observation suggests that NH₄-HPAN promotes hydrate formation by enhancing both the formation quantity and rate. Although no significant regularity in the effects on hydrate formation quantity or rate was observed with increasing NH₄-HPAN concentrations, it can be conclusively stated that NH₄-HPAN exerts a promoting effect on hydrate formation.

3.2.3. Nanoparticles—Flow Modifiers Composite Effect

Although the addition of LV-PAC improves the flow behavior of drilling fluids, the improvement effect is limited, and the generated shear force is insufficient, which hinders the drilling fluid’s ability to carry cuttings. Therefore, the incorporation of flow modifiers into the drilling fluid system is necessary. Guar gum [25], derived from guar seeds, exhibits excellent water solubility and low-dosage viscosity enhancement, making it a suitable rheology modifier. Sesbania gum [26], extracted from sesbania seeds, features good solubility and is commonly used as a viscosifier. XC gum (Xanthan gum) [27] demonstrates unique solubility, superior rheology, and low-concentration thickening capability, serving as a dual-function additive for viscosity and filtration control. HV-PAC [28], similar to LV-CMC [29], dissolves readily in water, resists salts/heat/bacteria, and effectively improves viscosity at low dosages, finding wide application in drilling engineering.

This section focuses on the effects of different flow modifiers combined with CaCO₃ on hydrate formation. The experimental data are presented in

Table 7. Time–pressure experimental data obtained by combining 3% CaCO₃ with five flow modifiers.

Sample Measurement	t1 (min)	t2 (min)	P1 (MPa)	P2 (MPa)
3%CaCO3	74.85	1197.42	5.748	4.022
3%CaCO3 + 0.3%XC	125.20	1451.63	5.838	5.041
3%CaCO3 + 0.3%Guar gum	~	~	5.726	5.726
3%CaCO3 + 0.3%Sesbania gum	~	~	5.786	5.786
3%CaCO3 + 0.3%HV-CMC	~	~	5.764	5.761
3%CaCO3 + 0.3%HV-PAC	~	~	5.757	5.755

Note: “~” indicates no hydrate formation.

and

Table 8. Calculation results for five cases of 3% CaCO₃ combined with flow modifiers.

Sample Measurement	Induction Time (min)	Hydrate Formation (mol)	Average Hydrate Formation Rate (×10−3 mol/min)
3%CaCO3	74.85	0.336	0.299
3%CaCO3 + 0.3%XC	125.20	0.159	0.123
3%CaCO3 + 0.3%Guar gum	~	~	~
3%CaCO3 + 0.3%Tian Jing powder	~	~	~
3%CaCO3 + 0.3%HV-CMC	~	~	~
3%CaCO3 + 0.3%HV-PAC	~	~	~

Note: “~” indicates no hydrate formation.

.

As shown in the experimental data and calculation results of Table 7 and Table 8, compared with the base fluid, the five flow modifiers exhibited significant inhibitory effects on hydrate formation. The addition of 0.3% guar gum, sesbania gum, HV-CMC, and HV-PAC completely suppressed hydrate formation, indicating the strong inhibition capabilities of these four flow modifiers. When 0.3% XC was added, it also demonstrated a notable inhibitory effect on hydrate formation: compared with the base fluid, the induction time was extended by 67.27%, the hydrate formation quantity was reduced by 52.69%, and the average formation rate was decreased by 58.86%, confirming that 0.3% XC effectively retarded hydrate formation. Comprehensive analysis shows that at a 0.3% dosage of flow pattern regulators, guar gum, sesbania gum, HV-CMC, and HV-PAC completely inhibited hydrate formation, while XC also exerted a significant inhibitory effect. Flow modifiers (such as xanthan gum, cellulose-based, and nanocomposite systems) compounded with nano-CaCO₃ achieve inhibitory effects by reducing interfacial energy, hindering mass transfer, and competing for free water molecules (Figure 7e) [17,30].

Building on these findings, different concentrations of XC were added to the base mud to investigate the synergistic effects of CaCO₃ and XC on hydrate formation. The corresponding reaction initiation/termination times and pressures are detailed in

Table 9. The influence of XC and 3% CaCO₃ at different concentrations on hydrate formation.

Sample Measurement	t1 (min)	t2 (min)	P1 (MPa)	P2 (MPa)
3%CaCO3	74.85	1197.42	5.748	4.022
3%CaCO3 + 0.1%XC	71.65	1260.37	5.754	4.338
3%CaCO3 + 0.2%XC	85.03	1285.20	5.787	4.519
3%CaCO3 + 0.3%XC	125.20	1451.63	5.838	5.041
3%CaCO3 + 0.4%XC	80.12	1225.60	5.724	4.732
3%CaCO3 + 0.5%XC	46.37	1355.62	5.928	4.761

. Hydrate formation quantities and rates for all samples were calculated by substituting the data from Table 9 into Equations (1) and (2), with the computational results graphically presented in Figure 8.

As shown in Figure 8 and Table 9, when the xanthan gum (XC) concentration ranged from 0.1% to 0.3%, the induction time of hydrate formation progressively extended with increasing XC concentration, consistently exceeding that of the XC-free experimental group. At 0.3% XC, the induction time attained its maximum value, indicating that the drilling fluids’ hydrate inhibition capability reached peak efficacy at this concentration. However, when the XC concentration increased to 0.4%, its ability to prolong the induction time diminished compared to the 0.3% XC system. Notably, at 0.5% XC, the induction time was shorter than that of the XC-free group, suggesting a promotive effect on hydrate nucleation under this condition. These findings demonstrate that within the 0.1–0.3% XC concentration range, the hydrate inhibition capability of the drilling fluid strengthens progressively with increasing XC concentration, peaking at 0.3%. Conversely, at higher concentrations (0.4–0.5%), the inhibitory effect weakens due to the enhanced foaming capacity and foam stability of the solution, which may interfere with hydrate suppression. In conclusion, XC effectively inhibits hydrate formation, with its maximum inhibitory capacity achieved at a 0.3% concentration.

4. Conclusions

In this study, the composite effects of nanoparticles and conventional drilling fluid additives on hydrate formation in seawater-based drilling fluids were investigated by recreating the high-pressure, low-temperature marine environment. The experimental results show that 20 nm hydrophilic CaCO₃ significantly suppresses methane hydrate formation in artificial seawater systems containing sepiolite, with the optimal inhibitory effect achieved at a concentration of 3.0%. When combined with sepiolite, the system exhibits a promoting effect. In the composite systems with 0.2% filtrate reducers, LV-PAC, CMS, and LV-CMC prolong the induction time (CMS > LV-PAC > LV-CMC), whereas SMP-2 and NH₄-HPAN shorten it. Notably, the combination of nano-CaCO₃ with five selected flow modifiers effectively suppresses methane hydrate formation. Among these, XC exhibits a relatively weaker inhibitory capacity with an optimal concentration of 0.3%, beyond which the inhibitory effect diminishes.

These findings fill the gap in the application of nanoparticles in hydrate drilling fluid systems. However, considering the complexity of real-world marine drilling operations (such as varying formation characteristics, dynamic drilling fluid circulation, etc.), there may be discrepancies between the simulated experiments and actual field conditions. Future research will focus on experiments that more closely simulate real drilling conditions, taking into account factors such as formation characteristics, dynamic drilling fluid circulation, and temperature–pressure fluctuations.