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Review

Instability Mechanisms and Wellbore-Stabilizing Drilling Fluids for Marine Gas Hydrate Reservoirs: A Review

1
School of Environmental Science and Engineering, Guangdong University of Technology, Guangzhou 510006, China
2
Shenzhen Key Laboratory of Natural Gas Hydrates & Academy for Advanced Interdisciplinary Studies, Southern University of Science and Technology, Shenzhen 518055, China
3
Petroleum College, China University of Petroleum-Beijing at Karamay, Karamay 834000, China
*
Author to whom correspondence should be addressed.
Energies 2025, 18(16), 4392; https://doi.org/10.3390/en18164392
Submission received: 16 July 2025 / Revised: 10 August 2025 / Accepted: 15 August 2025 / Published: 18 August 2025
(This article belongs to the Section H1: Petroleum Engineering)

Abstract

The safe exploitation of marine natural gas hydrates, a promising cleaner energy resource, is hindered by reservoir instability during drilling. The inherent temperature–pressure sensitivity and cementation of hydrate-bearing sediments leads to severe operational risks, including borehole collapse, gas invasion, and even blowouts. This review synthesizes the complex instability mechanisms and evaluates the state of the art in inhibitive, wellbore-stabilizing drilling fluids. The analysis first deconstructs the multiphysics-coupled failure process, where drilling-induced disturbances trigger a cascade of thermodynamic decomposition, kinetic-driven gas release, and geomechanical strength degradation. Subsequently, current drilling fluid strategies are critically assessed. This includes evaluating the limitations of conventional thermodynamic inhibitors (salts, alcohols, and amines) and the advancing role of kinetic inhibitors and anti-agglomerants. Innovations in wellbore reinforcement using nanomaterials and functional polymers to counteract mechanical failure are also highlighted. Finally, a forward-looking perspective is proposed, emphasizing the need for multiscale predictive models that bridge molecular interactions with macroscopic behavior. Future research should prioritize the development of “smart”, multifunctional, and green drilling fluid materials, integrated with real-time monitoring and control systems. This integrated approach is essential for unlocking the potential of marine gas hydrates safely and efficiently.

1. Introduction

Natural gas hydrates (NGHs), crystalline cage compounds of water and natural gas molecules (predominantly methane), form under specific high-pressure and low-temperature conditions [1,2,3,4,5]. Globally distributed in permafrost regions and submarine sediments at depths typically exceeding 300 m [6], NGHs are estimated to contain carbon resources rivaling those of all known conventional fossil fuel resources [7,8,9,10,11]. Marine NGH deposits account for over 97% of this total inventory [12], making their exploitation a strategic imperative for enhancing global energy and optimizing the future energy mix [13,14]. However, converting this vast resource potential into a viable energy supply is impeded by severe technical challenges, foremost among them being the control of reservoir stability during drilling—a primary bottleneck to commercialization [15,16,17]. Marine NGH reservoirs are typically hosted in shallow, unconsolidated, or weakly cemented soft sediments. Within this matrix, hydrate crystals function as both pore-filling and cementing agents, contributing critically to the mechanical strength and stability of the reservoir skeleton [18]. Drilling operations inevitably disrupt the dedicated in situ thermo-hydraulic–mechanical–chemical (THMC) equilibrium, triggering a cascade of deleterious reactions. Heat introduced from circulating drilling fluid and bit-formation friction, coupled with filtrate invasion driven by pressure differentials, can elevate local temperatures or reduce effective pressures. These perturbations may push the hydrate beyond its thermodynamic stability boundary, inducing decomposition [19].
This phase transition releases significant volumes of gas and water, causing a surge in pore pressure that diminishes effective stress and compromises wellbore integrity. The potential consequences are severe, ranging from sand production and shallow gas influx to catastrophic blowouts [20]. Simultaneously, the loss of hydrate as a cementing agent drastically reduces the sediment’s mechanical properties, such as compressive strength and cohesion. The weakened near-wellbore formation is then highly susceptible to plastic deformation and collapse under the combined load of the drilling fluid column and in situ stresses. Consequently, wellbore instability in NGH drilling is a far more complex challenge than in conventional reservoirs, governed by the intricate coupling of THMC processes [21,22].
Addressing this challenge necessitates the development of advanced drilling fluids engineered for both strong inhibition and robust wellbore stabilization [23,24]. An ideal NGH drilling fluid must fulfill three critical functions: (i) strong thermodynamic inhibition to expand the hydrate stability window by lowering the hydrate equilibrium temperature [25]; (ii) effective kinetic inhibition and anti-agglomeration to retard decomposition rates and prevent dissociated molecules from re-forming into obstructive masses [26,27]; and (iii) superior wellbore strengthening and sealing to form a low-permeability filter cake that minimize heat exchange and fluid invasion while mechanically reinforcing the near-wellbore region [28,29].
In pursuit of these criteria, extensive research has yielded a technological evolution from simple saline systems to advanced water-based drilling fluids (WBDFs) and oil-based drilling fluids (OBDFs) [30,31]. Despite this progress, significant limitations persist. WBDFs often exhibit insufficient inhibitive capacity, while OBDFs, despite superior performance, present high costs, environmental risks, and the potential for non-phase-change hydrate dissolution. Achieving an optimal balance among inhibition efficacy, wellbore stability, environmental compatibility, and cost-effectiveness remains a paramount challenge.
This work provides a systematic review of the instability mechanisms governing marine NGH reservoirs and the state of the art in inhibitive, wellbore-stabilizing drilling fluids. It begins by analyzing the coupled THMC processes from thermodynamic, kinetic, and geomechanical perspectives. Subsequently, the design strategies, performance attributes, and limitations of various drilling fluid systems are comprehensively assessed. Finally, future trends are projected based on recent advances in theory, materials science, and monitoring technologies. This review aims to furnish a foundation reference to guide future research toward the safe, efficient, and sustainable exploitation of marine NGH resources.

2. Mechanisms of Gas Hydrate Reservoir Destabilization

2.1. Thermodynamic Destabilization

Thermodynamic destabilization is the fundamental process governing the instability in NGH reservoirs. It can occur when drilling activities (as well as natural geological processes [32,33,34,35,36]) disrupt high-pressure and low-temperature conditions essential for hydrate stability, thereby inducing a phase transition from solid hydrate to its constituent gas and water phases [37]. This decomposition can trigger a cascade of geohazards, including large-scale submarine landslides [38,39,40,41,42,43]. The stability of NGH is thermodynamically defined by its phase equilibrium boundary on a pressure–temperature (P-T) diagram (Figure 1). For any given pressure, there exists a critical equilibrium temperature above which hydrates decompose; conversely, for a given temperature, there is a critical equilibrium pressure below which they destabilize [44,45,46].
Drilling operations perturb this delicate equilibrium primarily through two pathways: temperature elevation and pressure reduction [47,48,49]. Temperature elevation is the most direct destabilization trigger. Multiple heat sources contribute during drilling:
  • Drilling fluid circulation: Circulating drilling fluid, even after cooling in the marine riser, typically has a temperature higher than that of the seabed formation. Continuous convective and conductive heat transfer from fluid elevates near-wellbore temperatures [50].
  • Frictional heating: the rotating drill bit generates substantial localized heat during rock fracturing, causing significant temperature spikes at the bottom of the hole [51].
  • Viscous dissipation: additional heat is generated by the shear of the rotating drill string and the high-velocity fluid flow [52,53].
These combined effects establish a temperature gradient from the wellbore into the formation. When the wellbore wall temperature exceeds the hydrate equilibrium temperature at the in situ pressure, decomposition initiates. Although the strongly endothermic decomposition reaction (~54.2 kJ/mol for methane hydrate) creates a thermal buffer that shows the temperature rise, sustained heating influx from the wellbore ensures the decomposition front propagates radially outwards. This process creates an inner and weakened zone characterized by high pore pressure and low mechanical strength, which directly contributes to wellbore enlargement [54].
Pressure reduction is another critical trigger. While NGH drilling typically conducted in an overbalance pressure condition to maintain wellbore stability, the downhole pressure regime is highly dynamic [55].
  • Operational fluctuations: Routine operations, such as pump start/stop cycles, or pipe connections, cause transient pressure drops from circulating to static conditions. These fluctuations can momentarily depress the bottom-hole pressure below the hydrate equilibrium pressure, particularly in reservoirs with narrow thermodynamic stability windows [56].
  • Rapid pore pressure elevation [57]: Hydrate decomposition produces immense volumes of gas. For instance, 1 cm3 of solid methane hydrate can liberate approximately 164 cm3 of methane gas at standard conditions [58]. The release of this gas into a confined pore volume causes an abrupt and significant increase in pore pressure. This overpressure then propagates rapidly through the newly formed high-permeability network. If this pressure front reaches the wellbore and exceeds the hydrostatic pressure of the drilling fluid, it will trigger a gas influx, which can escalate into a blowout.
  • Swab pressures: Rapid tripping of the drill string upward in the wellbore generates a transient low-pressure zone immediately below the drill bit, known as the “swabbing” effect [59]. This phenomenon occurs as the upward movement of the drill string generates a transient reduction in bottom-hole pressure by drawing fluids upward faster than they can be replaced, thereby destabilizing hydrates near the wellbore.
Critically, the decomposition process itself generates a powerful feedback loop. The release of large volumes of gas into the pore space causes a sharp elevation in pore pressure. According to Terzaghi’s principle, this increased pore pressure reduces effective stress on the sediment framework, further compromising its stability and blowouts [60,61,62].
In summary, thermodynamic destabilization is the initiating event in most NGH drilling-related instability scenarios [37,63]. The temperature and pressure of the drilling fluid are the key operational parameters. Any condition that either elevates the near-wellbore temperature above the equilibrium threshold or reduces the effective pressure below it will trigger decomposition. Therefore, a primary objective of NGH drilling fluid design is to implement thermodynamic inhibition. Incorporating inhibitors like salts or alcohols shifts the hydrate phase boundary to lower temperatures and higher pressures, effectively expanding the safe operating window and suppressing thermodynamic destabilization at its source [64,65,66].

2.2. Kinetic Destabilization

Even when drilling conditions move the near-wellbore environment into the hydrate instability zone, decomposition is not instantaneous; it is governed by distinct kinetic processes [67,68,69]. The study of kinetic destabilization focuses on three interconnected aspects: the rate of hydrate decomposition, the transport of decomposition products (gas and water), and their profound impact on reservoir permeability and pore pressure [70]. The uncontrolled acceleration of these kinetic processes is the direct cause of severe drilling incidents including gas influx and well kicks [71].
To elucidate how these macroscopic kinetic constraints emerge from molecular-scale events, Figure 2 presents a conceptual three-step decomposition mechanism at the microscopic level. As depicted, the process initiates with the desorption of guest molecules from the hydrate lattice, followed by the outward mass transfer of released gas and water, and terminates within a distinct hydrate-decomposition layer. The overall rate of hydrate decomposition is fundamentally governed by the kinetics of these individual steps and the efficiencies of the associated heat and mass transfer processes. This rate is influenced by multiple factors, including the degree of superheating (temperature deviation above equilibrium), intrinsic kinetics, and the efficiencies of heat and mass transfer [72,73]. While a larger degree of superheating provides a stronger driving force for initial decomposition, the process is a strongly endothermic (ΔH ≈ 54.2 kJ/mol for methane hydrate [74]). This endothermicity creates a negative feedback loop by consuming ambient heat and depressing the temperature at the decomposition interface. Consequently, sustained decomposition is critically dependent on the rate of heat transfer from the wellbore.
Mass transfer also plays a crucial role, often manifesting as “self-preservation” and the “memory effect”. For decomposition to continue, the resulting gas and water must be transported away from the reaction interface. If these products accumulate, they can form an insulating film that impedes heat transfer to the remaining hydrate—a phenomenon known as the self-preservation effect [75,76]. Furthermore, the liberated water retains a “memory” of the hydrate structure, which can significantly reduce the induction times for hydrate re-formation if thermodynamic conditions again become favorable [77,78].
In the context of drilling, kinetic destabilization has several critical consequences for the reservoir–wellbore system:
  • Catastrophic permeability increase: Hydrate-bearing sediments are typically characterized by low permeability due to hydrate crystals occluding pore throats. Upon hydrate decomposition, this solid phase transforms into mobile fluids, causing permeability to increase by several orders of magnitude (e.g., from 10−3 mD to more than 103 mD) [79,80,81]. This dramatic shift transforms zones that once impermeable barriers into high-flux conduits, which can compromise the integrity of caprocks and overlying formations [82,83,84].
  • Rapid gas mobilization: During hydrate decomposition, the gas release rate can far exceed the dissipation capacity of the surrounding formation, particularly when triggered in zones with sharply increased permeability. This rapid mobilization produces high-velocity gas–water flows that can erode fine sediments, enlarge pore channels, and further accelerate decomposition. Such positive feedback between gas liberation and sediment destabilization can rapidly evolve into uncontrolled fluid migration toward the wellbore, amplifying the risk of gas influx and well control challenges [85].
Secondary hydrate formation: A unique and hazardous kinetic phenomenon is the formation of secondary hydrates. Gas liberated from deep, warm zones can migrate upward into colder regions of the wellbore, such as the upper annulus. There, it can react with free water in the drilling fluid to form new hydrate solids [16]. These secondary hydrates often manifest as flocculent or massive blockages, rapidly obstructing the annulus, choke lines, and blowout preventers (BOPs), thereby compromising well control operations [86,87].
Therefore, managing kinetic destabilization requires controlling both the decomposition rate and product transport of its products. An effective drilling fluid must incorporate kinetic inhibitors (KHIs) [88] or anti-agglomerants (AAs) [89] in addition to thermodynamic inhibitors (THIs). These additives can adsorb onto hydrate crystal surfaces, hindering molecular dissociation or re-agglomeration. This provides a crucial time window to conduct drilling operations safely, even under transiently unstable conditions. Concurrently, the fluid must form an effective sealing barrier to restrict the mobility of decomposition products, thereby retarding pore pressure transmission and controlling the overall progression of kinetic failure.
Figure 2. Conceptual model for three-step hydrate decomposition mechanism at microscopic level. The red arrow represents the desorption of the guest molecule, the blue arrow represents the mass transfer process, the red dotted rectangle represents the hydrate decomposition layer, and the blue dotted line represents the interface between gas hydrate and gas phases [90].
Figure 2. Conceptual model for three-step hydrate decomposition mechanism at microscopic level. The red arrow represents the desorption of the guest molecule, the blue arrow represents the mass transfer process, the red dotted rectangle represents the hydrate decomposition layer, and the blue dotted line represents the interface between gas hydrate and gas phases [90].
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2.3. Mechanical Destabilization

Mechanical destabilization is the ultimate physical manifestation of hydrate reservoir instability, evidenced by borehole collapse, spalling, and sand production. This structural failure is not an isolated event but the culmination of thermodynamic and kinetic process, leading to rapid deterioration of the formation’s mechanical properties amid a redistribution of in situ stresses [91,92]. The intrinsic mechanical strength of hydrate-bearing sediments, particularly those in shallow, unconsolidated marine deposits, is derived from three primary components: inter-granular friction, clay-based cohesive bonds, and, most importantly, the cementing strength and pore-filling support provided by hydrate crystals themselves [18,93,94].
The destabilization process is driven by several interconnected geomechanical mechanisms:
  • Loss of cementation and strength degradation: This is the most fundamental failure mechanism. As hydrates decompose, the phase transition converts load-bearing solids into non-load-bearing pore fluids (gas and water). This loss of the primary cementing agent causes a catastrophic reduction in the sediment’s cohesive strength and stiffness. The formation effectively transitions from a weakly cemented rock to a loose, unconsolidated sand, rendering it highly susceptible to shear or tensile failure under ambient stress conditions, which leads to borehole collapse and spalling [45].
  • Reduction in effective stress: The stability of the sediment skeleton is governed by effective stress (σ’), defined by Terzaghi’s principle as the total stress (σ) minus the pore pressure (Pp): σ’ = σ − Pp. As established, hydrate decomposition induces an abrupt elevation in Pp. Even if the total stress remains constant, this rise in pore pressure significantly reduces the effective stress acting on the rock framework. When σ’ falls below the sediment’s yield strength, plastic deformation and failure occur. This process, known as poroelastic instability, is a critical pathway for mechanical destabilization in NGH reservoirs [95,96].
  • Wellbore stress concentration: The act of drilling creates a cavity that disrupts the original triaxial stress state of the formation. Stress redistributes around the wellbore, creating zones of high stress concentration, typically orientated perpendicular to the maximum horizontal stress direction. For a formation already weakened by hydrate decomposition, even routine stress concentrations can be sufficient to exceed its diminished failure envelope, initiating borehole breakouts with characteristic “V” or “U” shapes [97,98].
Collectively, these processes can culminate in reservoir collapse, submarine slope failure, and the cascade of seismic, landslide, or tsunami hazards illustrated schematically in Figure 3.
The consequence of this mechanical failure is often severe sand production. Disaggregated grains are entrained by circulating drilling fluid and flowing gas, leading to progressive cavity formation and wellbore enlargement [99,100,101]. This complicates subsequent casing and cementing operations and may induce stuck pipe incidents [102,103]. The critical nature of this problem was highlighted during Japan’s Nankai Trough production tests, where two separate trials were prematurely terminated due to massive sand influx, highlighting the necessity of robust sand control [104,105].
To counteract mechanical destabilization, an advanced drilling fluid must provide exceptional wellbore strengthening and sealing [106]. This requires a dual-action strategy: first, suppressing hydrate decomposition to preserve the rock’s intrinsic strength, and second, when decomposition is inevitable, rapidly forming a high-strength, low-permeability barrier on the wellbore wall. This “engineered filter cake”, created by a synergy of bridging particles and film-forming polymers, seals pores and micro-fractures. It functions as an artificial support structure, partially replacing the loss of hydrate cementation, enhancing residual rock strength, and impeding pore pressure transmission to the wellbore. By maintaining a higher effective stress, this barrier inhibits further deformation and ensures mechanical integrity.
Figure 3. Schematic representation of a possible mechanism for initiating submarine landslides by methane hydrate dissociation [107].
Figure 3. Schematic representation of a possible mechanism for initiating submarine landslides by methane hydrate dissociation [107].
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3. Advanced Drilling Fluid for Hydrate Wellbore Stability

To address the complex multiphysics-coupled destabilization mechanisms, drilling fluid technology for gas hydrates has evolved from single-function formulations to multifunctional integrated ones [23,108,109]. This represents a shift from passive adaptation to active control. The core design philosophy centers on the synergistic application of two strategies: inhibition and wellbore stabilization [110]. Inhibition aims to prevent or delay hydrate decomposition, serving as the primary line of defense. Wellbore stabilization act as a critical safeguard, reinforcing wellbore structural integrity of the formation when decomposition becomes unavoidable [111].

3.1. Thermodynamic Inhibitors

THIs function by reducing the activity of water, thereby shifting the hydrate phase equilibrium boundary to lower temperatures and higher pressures. This action expands the safe operational window for drilling by making the thermodynamic conditions required for hydrate nucleation more stringent [112]. Figure 4 demonstrates how THIs can shift the hydrate equilibrium curve, effectively lowering the formation temperature or increasing the required pressure, thereby enhancing drilling safety margins. THIs are categorized into inorganic salts and organic compounds.

3.1.1. Inorganic Salts

Inorganic salts such as NaCl, KCl, and CaCl2 are the most common and cost-effective THIs. Upon dissolution, their constituent ions hydrate, reducing the number of free water molecules available for clathrate cages. Inhibition efficacy is directly proportional to salt concentrations [113]. Fu et al. [114] systematically measured methane hydrate phase equilibria in various salt solutions (NaCl, KCl, KBr, and NaBr) at temperatures between 274 and 282 K, demonstrating significant thermodynamic inhibition. Li et al. [115] found that MgCl2 provided the strongest inhibition among common chloride salts. Kim et al. [116] reported that adding 3.5 wt% NaCl to solution of monoethylene glycol or methanol (5 wt%) synergistically enhanced hydrate inhibition.
Despite their effectiveness, high-salinity brines present several major drawbacks: they are highly corrosive to drilling tubulars, pose significant environmental risks upon discharge, and impair the performance of common drilling polymers (e.g., viscosifiers, fluid loss agents) through salting-out effects, complicating fluid maintenance [117].

3.1.2. Alcohols and Amines

Organic compounds like ethylene glycol (MEG), glycerol, and methanol represent another class of effective THIs. They function similarly to salts by forming strong hydrogen bonds with water molecules, thereby reducing water activity. Du et al. [118] observed that methanol concentrations above 40 wt% significantly shifted the methane hydrate phase equilibrium towards lower temperatures, confirming its strong thermodynamic inhibition capability. Aminnaji et al. [119] demonstrated that methanol/MEG mixtures were more effective at removing hydrate plugs than either component alone. Keshavarz et al. [120] showed that certain amines, like (3-Aminopropyl) triethoxysilane (APTES), (3-Aminopropyl) triethoxysilane (APTMS), and Triethylenetetramine (TETA), could also effectively shift methane hydrate equilibria conditions. While alcohols like MEG offer benefits such as recyclability and reduced volatility, others like methanol exhibit higher ecotoxicity, possess relatively limited biodegradability, and pose significant environmental hazards and high wastewater treatment costs [121,122].

3.2. Kinetic Inhibitors and Anti-Agglomerants

When thermodynamic inhibition alone is insufficient or when reducing the concentration of THIs is desired, KHIs and AAs offer a complementary control strategy. Applied at low dosages (typically 0.1–2 wt%), these additives manage the kinetics of hydrate formation and decomposition, providing transient protection without altering the thermodynamic phase boundary [123]. As illustrated in Figure 5, KHIs primarily function by extending the induction time prior to rapid hydrate growth, thereby offering a critical time window to ensure safe drilling operations under subcooling conditions.
KHIs are typically low-molecular-weight polymers, with polyvinylcaprolactam (PVCap) and polyvinylpyrrolidone (PVP) being prominent examples [124]. KHIs function by adsorbing onto the surface of nascent hydrate crystals. Their functional groups, such as the amide groups in PVCap, can either embed within the clathrate cages or bind to crystal growth sites. This action, driven by hydrogen bonding and steric hindrance, disrupts further crystal lattice development. While unable to prevent nucleation, KHIs can substantially prolong the induction time before rapid growth occurs, thereby creating critical operational window for drilling activities. Liu et al. [125] evaluated several KHIs and identified 1.0 wt% of PVCap as optimal, extending induction time to 1000 min. Using confocal Raman microscopy, Zhang et al. [126] visually confirmed that PVCap effectively delayed methane hydrate growth at the gas–liquid interfaces.
The primary advantages of KHIs include their low dosage, moderate cost, and lower environmental impact compared to THIs. Although the vast majority of KHIs are low in acute toxicity and bioaccumulation, very few commercial products show good biodegradability, and for that reason, there is always some concern of long-term chronic toxicity from partially degraded products if discharged into the environment [127]. Additionally, their effectiveness is typically limited to moderate subcooling conditions (generally <10–12 °C) and they are often less effective at inhibiting decomposition than formation, which can be a limitation under severe downhole temperature fluctuations.
AAs, such as quaternary ammonium salts like tetrabutylammonium bromide (TBAB) [128], function as surfactants. Unlike KHIs, AAs permit hydrate nucleation and growth but prevent the small crystals from agglomerating into a solid and obstructive mass. The amphiphilic structure of AAs is key to this mechanism: their hydrophobic tails adsorb onto the hydrate crystal surface, while their hydrophilic heads extend into the aqueous phase. This creates a stabilizing layer that prevents inter-particle adhesion through electrostatic repulsion and steric hindrance, resulting in a transportable, non-plugging hydrate slurry.
While AAs are well-established in pipeline flow assurance, their application in complex drilling fluids remains exploratory. Key challenges include ensuring their chemical compatibility with other, often anionic, drilling fluid additives and maintaining their long-term stability under harsh downhole conditions. Crucially, AAs are typically non-biodegradable; consequently, if released from pipelines into the marine environment, they pose severe ecological impacts. Moreover, conventional AA materials exhibit high toxicity and tend to bioaccumulate in organisms [129].
Figure 5. Conceptual diagram of the hydrate formation process and the critical time points in KHI solutions [130].
Figure 5. Conceptual diagram of the hydrate formation process and the critical time points in KHI solutions [130].
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3.3. Wellbore Strengthening and Sealing Technologies

Wellbore strengthening and sealing are critical for mitigating mechanical destabilization [131,132]. The primary objective is to establish a robust and low-permeability barrier on the wellbore wall. Conventional technology relies on bridging particles, using materials with a tailored size distribution (e.g., ultrafine calcium carbonate, sulfonated asphalt, nut shells) to seal pore throats and form compact filter cakes. However, the dynamic pore structure of a decomposing hydrate reservoir demands a more advanced approach.
Nanotechnology has revolutionized sealing capabilities. Nanoparticles (e.g., nano-silica, nano-CaCO3, graphene) can penetrate and seal micro- to nano-scale pores and microfractures, creating an ultra-low-permeability barrier deep within the formation matrix [133,134,135,136,137]. Certain nanofluids can also alter rock wettability to be more hydrophobic, further inhibiting aqueous filtrate invasion [138]. Despite promising lab studies, scalable production, stable dispersion in drilling fluids, and environmental risk assessment remain key challenges for field deployment. Flexible polymers and chemical consolidation agents provide complementary stabilization. Flexible materials, such as deformable polymer microspheres, can extrude into irregularly shaped fractures to provide a more effective seal [139,140,141]. Film-forming agents like sulfonated asphalts or resins create a ductile layer on the wellbore wall, offering mechanical support and micro-fracture sealing [142,143,144]. Chemical consolidators (e.g., silicates, organic crosslinkers) can react in situ to generate insoluble precipitates or gels. This process cements loose grains together, directly enhancing the formation’s intrinsic strength. However, this approach requires precise control to avoid unintended formation damage [145,146].
To synthesize the characteristics of these diverse functional additives, Table 1 provides a comparative summary of their performance attributes, relative costs, environmental impacts, and key limitations. This comparison highlights the trade-offs inherent in selecting components for an integrated drilling fluid system.
This comparative analysis reveals that no single additive class offers a perfect solution. The selection and combination of these components are therefore a complex optimization problem, aiming to maximize synergistic effects while mitigating inherent drawbacks. The subsequent section discusses how these additives are integrated into coherent drilling fluid systems to address the multifaceted challenges of hydrate drilling.

3.4. Integrated Fluid Systems

Meeting the stringent demands of hydrate drilling requires the scientific integration of these functional additives into stable and high-performance fluid systems. The primary systems under development and in use are WBDFs, OBDFs, and synthetic-based drilling fluids (SBDFs).
WBDFs are the preferred system for offshore hydrate drilling due to their lower cost and environmental impact. Modern formulations synergistically combine thermodynamic and KHIs with advanced sealing agents and specialized low-temperature polymers [147,148,149,150,151]. For example, successful drilling in Japan’s Nankai Trough employed a KCl–polymer + sepiolite system [147], while China’s Shenhu trials utilized a composite “salt + alcohol” fluid enhanced with multimodal sealing materials, ensuring wellbore stability during extended production tests [152]. Research continues to optimize WBDFs, such as the potassium formate-based system developed by Morenov et al. [153] for shale inhibition in high-pressure intervals.
The non-aqueous fluids (NAFs), including OBDFs and SBDFs, feature a continuous oil or synthetic phase with an emulsified high-salinity brine. They offer superior inhibition, lubricity, and thermal stability [154,155]. SBDFs, using synthetic organic bases, have become vital for complex offshore wells due to their excellent performance characteristics [156]. However, NAFs face significant challenges in hydrate applications. They exhibit problematic rheological behavior at low temperatures, such as gelation and viscosity spikes, which can impair hole cleaning and cause downhole complications. Furthermore, their high cost, potential ecotoxicity, and complex waste management collectively limit their widespread use.
To provide a clear overview of how these integrated systems have been applied in practice, Table 2 summarizes the representative drilling fluid strategies employed in major marine gas hydrate drilling and production testing projects. These field cases highlight both the successes and the persistent challenges in maintaining wellbore stability in diverse marine hydrate settings.
As evidenced by these field trials, significant progress has been made, particularly with advanced water-based systems. The successful long-term stability achieved in the Shenhu Area underscores the potential of combining thermodynamic inhibition with active thermal management [161]. However, the severe sand production issues encountered in the Nankai Trough serve as a critical reminder that a fluid designed for drilling stability may not be sufficient to handle the dynamic stresses induced during production [162,163]. This points to a crucial gap between ensuring a stable wellbore during construction and maintaining its integrity throughout the asset’s life.
Current drilling fluid systems have demonstrated success in specific field trials, yet a universally applicable, “strong-inhibition and robust- stabilization” fluid remains elusive. A fundamental conflict persists between achieving high inhibitive performance and meeting environmental and economic constraints; strong inhibition often relies on high-concentration chemicals or energy-intensive equipment. Moreover, the existing systems are mostly passive and pre-designed, lacking the ability to dynamically adapt to changing downhole conditions. The synergy between various functional additives is often not fully optimized, presenting a major hurdle to achieving superior, integrated performance.

4. Future Trends and Perspectives

To overcome existing technological bottlenecks and meet the growing demand of commercial hydrate exploitation, the next generation of drilling fluids will be driven by advances in three interconnected domains: deeper theoretical understanding through advanced modeling, the development of advanced materials, and the implementation of intelligent monitoring and control systems.

4.1. Advanced Modeling

Current models of hydrate reservoir instability are often based on macroscopic phenomenological approaches or simplified single-physics simulations. This limits their ability to precisely predict wellbore responses under complex operational conditions. Future research must therefore advance toward greater depth, sophistication, and predictive power, explicitly addressing critical gaps between numerical simulations and experimental validation.
At the most fundamental level, computational chemistry techniques like molecular dynamics (MD) and density functional theory (DFT) are essential for unraveling the molecular-scale mechanisms governing hydrate behavior [164,165,166,167,168]. MD simulations provide critical insights into hydrate thermal stability, dissociation pathways, nucleation behavior, and the specific interactions between inhibitors and hydrate crystals [169,170,171,172,173,174,175]. For example, Kondori et al. [176] employed MD to elucidate the intermolecular forces at play during methane hydrate dissociation, while others have combined MD with quantum mechanics to probe the role of ions in hydrate formation [177]. Such simulations offer a “molecular microscope” to visualize how inhibitors like PVP function, providing the foundational knowledge needed to transition from empirical screening to the rational design of new, more effective inhibitor molecules [178]. However, techniques like high-resolution cryo-TEM (transmission electron microscopy) or advanced spectroscopic methods capable of observing inhibitor–hydrate interactions in situ are needed to confirm the mechanisms proposed by MD simulations.
Early modeling efforts focused on isolated thermal–hydraulic (TH) processes, primarily for assessing production potential [179,180]. In 1969, Raymond [181] developed a numerical model for transient and quasi-steady-state temperature distribution in the wellbore. However, the model did not account for internal heat sources or the influence of key drilling parameters on wellbore temperature, leading to limited accuracy in its predictions. Despite these limitations, this work laid an important theoretical foundation for the subsequent development of wellbore temperature field modeling. Sun et al. [65] developed a coupled temperature–pressure model for drilling fluids during the cementing stage, which aids in analyzing thermal effects and fluid performance during the circulation and injection process. Recognizing the critical role of geomechanics, these were later expanded into thermal–hydraulic–mechanical (THM) models, which could simulate stress–strain behavior, deformation, pore pressure evolution, and their feedback mechanisms—critical for evaluating wellbore stability and subsidence risks [182,183,184,185,186,187,188].
The current frontier is the development of fully coupled THMC models. As illustrated in Figure 6, these frameworks integrate not only heat transfer, fluid flow, and solid mechanics but also crucial chemical processes such as phase-change kinetics, salinity effects, and inhibitor transport [189,190,191]. Li et al. [192] developed a novel model integrating a sand production model with a THM model coupled model to predict gas and sand production during hydrate extraction. and this model was employed to elucidate the causes of the severe sand production observed in the Nankai Trough. Despite their sophistication, these models face major challenges in validation and parameterization due to several persistent knowledge gaps [193,194]:
  • Most THMC models rely on constitutive laws for hydrate-bearing sediments that are derived from static, quasi-equilibrium triaxial tests. There is a critical lack of experimental data and corresponding validated models that capture the dynamic, rate-dependent mechanical behavior of sediments during rapid dissociation, where properties like cohesion and friction angle change almost instantaneously. Future research must focus on developing and experimentally validating dynamic constitutive models that accurately reflect this transient weakening process.
  • Current models often use simplified relationships to describe how permeability changes with hydrate saturation and porosity. However, the strong coupling between mechanical deformation (e.g., pore collapse, micro-fracturing under stress) and fluid flow pathways is not well captured. We lack robust, experimentally verified models that dynamically link the evolving stress–strain state of the sediment to its anisotropic permeability tensor during decomposition.
  • There is a disconnect between pore-scale models that resolve individual grain and hydrate crystal interactions and continuum-scale reservoir models. Upscaling techniques that can accurately translate complex pore-scale physics (like the formation of localized high-permeability “wormholes” or the mechanics of filter cake formation with nanoparticles) into representative parameters (e.g., effective permeability, capillary pressure curves) for larger-scale THMC simulations are urgently needed.
Future THMC models must therefore not only pursue higher fidelity through 3D simulations and advanced fracture mechanics but also be co-developed with targeted experimental programs designed to close these gaps. This requires a stronger emphasis on large-scale, true-triaxial testing facilities equipped with advanced imaging (e.g., X-ray computed tomography) to simultaneously monitor deformation, fluid flow, and phase changes, providing the comprehensive datasets needed for rigorous model calibration and validation [195].
Finally, future models must move beyond deterministic predictions to embrace uncertainty. By incorporating stochastic methods like Monte Carlo simulations, models can perform uncertainty quantification (UQ) to generate probabilistic forecasts of wellbore instability [196,197]. This approach allows for the identification of the most sensitive parameters and enables a risk-based approach to drilling fluid design and operational decision-making, significantly enhancing safety and efficiency.
Figure 6. Coupling analysis of THMC fully coupled model [198].
Figure 6. Coupling analysis of THMC fully coupled model [198].
Energies 18 04392 g006

4.2. Intelligent and Eco-Friendly Materials

The next generation of drilling fluid materials will move beyond simple additive combinations toward smart responsiveness that are also environmentally sustainable.
Intelligent and responsive materials are essential for combating the dynamic instability risks in deepwater hydrate reservoirs [199]. Unlike passive inhibitors, smart materials can autonomously regulate their properties in response to environmental triggers. Thermoresponsive polymers are a prime example of this paradigm shift [200,201]. For example, Li et al. [202] developed thermoresponsive polymers exhibiting reversible sealing behavior. They form an impermeable filter cake to prevent fluid invasion (>3 MPa differential pressure) and suppress hydrate dissociation. However, these polymers then dissolve below their lower critical solution temperature (LCST—the temperature below which a polymer is soluble in a solvent and above which it phase-separates), enabling intelligent sealing and self-removing seals that are active during drilling but non-damaging during production. The specific mechanism of action is illustrated in Figure 7.
Eco-friendly and sustainable design has become non-negotiable criterion. Future research must prioritize green chemistry and biodegradability, given limited tolerance of marine ecosystems to pollutants. Multifunctional nanomaterials represent a key research and development direction for drilling fluid additives. These materials not only significantly enhance performance but also contribute to resolving environmental sustainability. Zamora et al. [203] demonstrated how vermiculite and graphene oxide 2D layered nanoparticles can improve the rheological and filtration performance of water-based drilling fluids. Tian et al. [204] developed a novel TiO2/Saponin/Zr nanocomposite for use as an additive in water-based drilling fluids. This nanocomposite significantly enhances the rheological properties, yield stress, and thermal stability of the drilling fluid, while maintaining good biodegradability. Functional polymers derived from natural and renewable sources—such as amino acids, sugars, alkaloids, modified starch, and lignin—offer promising pathways to creating high-performance additives that are fully biodegradable [205,206,207,208,209]. Complementing this is the development of closed-loop recycling technologies for high-value inhibitors (e.g., glycols), which will be critical for minimizing discharge and improving the economic feasibility of advanced systems [210,211,212].

4.3. Intelligent Drilling Systems: Real-Time Diagnosis and Dynamic Control

While advanced models and materials provide a powerful toolkit, their full potential can only be realized through precision monitoring and control. The ultimate goal is to transition hydrate drilling from an experience-based practice to a data-driven intelligent operation, form a closed-loop “perception-decision-execution” architecture. Figure 8 outlines the core components of an intelligent drilling system, integrating perception, decision-making, and execution modules to enable proactive wellbore risk control in hydrate-rich environments.
Logging-while-drilling (LWD) [213] and measurement-while-drilling (MWD) of critical parameters [214] technologies are critical for monitoring the rapidly changing conditions in hydrate formations. Beyond conventional measurements, next-generation sensor suites will include the following:
  • Acoustic logging: to detect hydrate dissociation in real-time by monitoring changes in sonic velocity and attenuation [215,216];
  • Nuclear magnetic resonance: to precisely quantify porosity, fluid type, saturation, and the location dissociation front [217,218,219];
  • Microseismic monitoring: to capture the acoustic emissions from rock micro-fracturing, providing an early warning of incipient mechanical failure. This data must be transmitted to the surface in real time via high-speed mud-pulse or electromagnetic telemetry [220,221].
The massive streams of data from these sensors will be processed by artificial intelligence (AI) algorithms. AI models leverage historical and real-time MWD/LWD data to predict sensor failures, optimize well placement, and identify drilling hazards [222]. Integration with AI facilitates lithology identification [223], stuck pipe prediction [224], casing resistance/wear assessment [225], and well trajectory monitoring [226]. Trained on extensive datasets, AI algorithms detect nonlinear coupled signatures (e.g., sudden temperature spikes, acoustic velocity drops, and microseismic clustering) to diagnose instability thresholds hours in advance, surpassing the sensitivity of conventional monitoring [226,227,228]. This AI-driven diagnostic capability transforms monitoring from a reactive to a predictive and proactive process.
The final piece is an automated control system that translates diagnostic insights into immediate action [229,230,231,232]. If the AI detects a high risk of thermodynamic destabilization, the system could automatically increase the power to surface cooling units or trigger the injection of a high-concentration inhibitor pill. If microseismic data indicates fracture initiation, it could autonomously deploy a targeted nano-sealant package. By integrating automated surface chemical dosing and flow control modules governed by adaptive algorithms, this closed-loop system enables proactive, precise, and real-time management of wellbore stability, fundamentally minimizing drilling risk.
Figure 8. Operational components of contemporary intelligent drilling systems [233].
Figure 8. Operational components of contemporary intelligent drilling systems [233].
Energies 18 04392 g008

5. Conclusions and Recommendations

Marine NGHs represent a massive potential energy resource. As the critical first step in their exploitation, drilling success is fundamentally dependent on controlling reservoir stability. This review, through systematic analysis of destabilization mechanisms and critical assessment of drilling fluid technologies, arrives at three principal conclusions:
  • NGH reservoir destabilization is a multiphysics-coupled process. Instability arises not caused by an isolated factor but by a tightly linked chain reaction involving thermodynamic decomposition, accelerated kinetic-driven fluid release, and mechanical strength degradation. This underscores that any viable stability solutions must holistically address the coupled thermal, hydraulic, mechanical, and chemical challenges. Strategies based on thermodynamic inhibition or mechanical sealing alone are insufficient.
  • Current drilling fluids lack true synergistic integration. By synergistic integration, we refer to the holistic design of drilling fluid formulations where the individual additives not only perform their respective functions but also enhance each other’s effectiveness without introducing trade-offs. While existing drilling fluid systems have demonstrated feasibility in specific field trials, they function primarily as a physical superposition of additives rather than as a synergistically engineered system. Potent inhibition often compromises rheological performance or environmental compatibility, and the long-term efficacy of sealing materials within complex chemical environments remains poorly understood.
  • Future breakthroughs hinge on cross-scale mechanistic understanding and precision material design. The primary limitation of current technology is an insufficient understanding of the microscopic interactions that govern macroscopic phenomena. Transformative advances will therefore emerge from foundational science—specifically, from cross-scale theoretical and experimental research that enables a predictive understanding of stabilization processes and facilitates the “design-on-demand” of new functional materials.
Building upon these conclusions, three prioritized research directions are recommended to advance marine NGH drilling fluids:
  • Investigate coupled mechanisms across scales. This requires a multi-pronged approach: (i) at the molecular scale, using simulations to elucidate inhibitor-hydrate interactions to guide rational inhibitor design; (ii) at the pore scale, using microfluidics and advanced imaging to model multiphase flow and sealing mechanisms within dynamic pore networks; and (iii) at the reservoir scale, developing fully coupled THMC numerical models that integrate these microscopic insights to accurately predict wellbore behavior under realistic drilling conditions.
  • Develop function-oriented intelligent and sustainable materials. Research should shift from passive defense to active response by designing “smart” materials (e.g., stimuli-responsive polymers) that can sense downhole triggers like temperature changes and autonomously activate sealing or inhibitive functions. Concurrently, a strong focus must be placed on eco-friendly materials, such as high-performance, biodegradable additives derived from renewable biomass, to ensure environmental compatibility.
  • Establish feedback control methodologies based on real-time monitoring. This involves three key steps: (i) developing AI-driven diagnostic algorithms that can identify subtle precursors to instability from real-time LWD/MWD data; (ii) building dynamic models that quantitatively link drilling fluid properties to wellbore stability status; and (iii) integrating these elements into closed-loop control systems that can automatically adjust fluid properties in real-time to proactively manage wellbore stability.
In summary, the future of NGH drilling fluid research lies in a paradigm shift: from addressing macroscopic problems to probing microscopic mechanisms; from developing single-function materials to constructing intelligent, multifunctional systems; and from practicing passive risk avoidance to implementing active, real-time control. Synergistic innovation across fundamental theory, advanced materials, and intelligent control holds the promise of resolving the global challenge of hydrate drilling instability, thereby laying a robust scientific foundation for the safe, economical, and sustainable development of this potential future energy resource.

Author Contributions

Conceptualization, G.Z.; writing—original draft preparation, Q.L. (Qian Liu) and B.X.; writing—review and editing, Y.L. and Q.L. (Qiang Li). All authors have read and agreed to the published version of the manuscript.

Funding

This research was funded by the Guangzhou Science and Technology Planning Project (SL2024A04J01144), and the APC was funded by Guangdong University of Technology.

Data Availability Statement

The original contributions presented in this study are included in the article. Further inquiries can be directed to the corresponding author.

Conflicts of Interest

The authors declare no conflicts of interest.

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Figure 1. Phase diagram of NGH. The solid black line indicates the phase equilibrium boundary between stable hydrate and dissociated phases. The vertical dashed red line marks the ice–water phase boundary at around 0 °C.
Figure 1. Phase diagram of NGH. The solid black line indicates the phase equilibrium boundary between stable hydrate and dissociated phases. The vertical dashed red line marks the ice–water phase boundary at around 0 °C.
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Figure 4. Example of hydrate equilibrium (no THI/THP, curve B) shift as a result of the addition of thermodynamic hydrate inhibitors (THIs, curve A) or thermodynamic hydrate promoters (THPs, curve C) [25].
Figure 4. Example of hydrate equilibrium (no THI/THP, curve B) shift as a result of the addition of thermodynamic hydrate inhibitors (THIs, curve A) or thermodynamic hydrate promoters (THPs, curve C) [25].
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Figure 7. Schematic illustration of self-unblocking and sealing mechanisms in thermo-responsive polymers [202]. The red dashed line represents the temperature trend: Above the seafloor, temperature decreases with increasing seawater depth; below the seafloor, friction between the drill bit and the reservoir generates heat, causing temperature to rise with depth.
Figure 7. Schematic illustration of self-unblocking and sealing mechanisms in thermo-responsive polymers [202]. The red dashed line represents the temperature trend: Above the seafloor, temperature decreases with increasing seawater depth; below the seafloor, friction between the drill bit and the reservoir generates heat, causing temperature to rise with depth.
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Table 1. Comparative analysis of key additives for inhibitive and wellbore-stabilizing drilling fluids.
Table 1. Comparative analysis of key additives for inhibitive and wellbore-stabilizing drilling fluids.
Additive CategoryExamplesPrimary Function and PerformanceRelative CostEnvironmental ImpactChallenges
Thermodynamic Inhibitors (THIs)–Inorganic Salts [113,114,115,116,117]NaCl, KCl, CaCl2Strong inhibition: significantly shifts hydrate phase boundary. Performance is concentration-dependent.LowHigh: high-salinity brine is difficult to treat, corrosive, and can harm marine life upon discharge.Highly corrosive to equipment; degrades polymer performance (salting-out); high concentration required.
Thermodynamic Inhibitors (THIs)–Alcohols/Glycols [118,119,120,121,122]Methanol, MEG, glycerolStrong inhibition: Effective water activity reduction. MEG is recyclable.Moderate to highModerate to high: Methanol is toxic and volatile. Glycols have high BOD/COD, requiring costly wastewater treatment.High dosage required (10–50 wt%); can affect fluid rheology; methanol poses safety risks.
Kinetic Hydrate Inhibitors (KHIs) [123,124,125,126]PVP, PVCapDelayed nucleation/growth: provides a “time window” of protection at low dosages (0.1–2 wt%).HighLow to moderate: generally better biodegradability and lower toxicity than THIs.Effective only under moderate subcooling (<12 °C); less effective against decomposition than formation; performance can be unpredictable.
Anti-Agglomerants (AAs) [129,130]Quaternary ammonium salts (e.g., TBAB)Prevents blockage: allows hydrate formation but keeps particles dispersed as a flowable slurry.HighModerate: some are surfactants with potential aquatic toxicity; requires careful selection.Compatibility issues with anionic polymers in WBDFs; long-term stability under downhole conditions is uncertain; primarily used in pipelines.
Bridging/Sealing Agents (Conventional) [131,132]CaCO3, sulfonated asphaltPore/fracture sealing: forms a filter cake to reduce permeability and fluid loss.Low to moderateModerate: some materials like asphalt have environmental concerns.Less effective in nano-pores; can cause formation damage if particle size is not matched; filter cake can be erosive.
Nanomaterials
[133,134,135,136,137]
Nano-SiO2, nano-CaCO3, grapheneDeep sealing and strengthening: penetrates nano-pores for an ultra-low permeability seal; reinforces filter cake structure.Very highUncertain/emerging concern: potential for bioaccumulation and long-term ecotoxicity is still under investigation.High cost of production; difficult to disperse and maintain stability in high-salinity brines; potential health and environmental risks.
Table 2. Summary of representative drilling fluid strategies in marine gas hydrate field projects.
Table 2. Summary of representative drilling fluid strategies in marine gas hydrate field projects.
Project/LocationYear(s)Drilling Fluid SystemKey Functional ComponentsPerformanceChallenges
Shenhu Area, South China Sea, China [157]2017, 2020Low-temperature, composite salt + glycol WBDF with active coolingNaCl/KCl + glycol (thermodynamic inhibition); multi-modal particles (sealing); low-temperature polymers (rheology).Successfully maintained wellbore stability for >60 days of continuous production testing; minimal hole enlargement observed. Proved the viability of the “active cooling” strategy.High energy consumption and complex logistics associated with the surface cooling systems.
Nankai Trough, Japan [158]2013, 2017KCl/polymer WBDFKCl (thermodynamic inhibition); Partially Hydrolyzed Polyacrylamide (PHPA) for shale stability; sepiolite for rheology control.Enabled successful drilling, coring, and casing operations in hydrate-bearing intervals.Encountered severe sand production during the depressurization production phase, leading to premature test termination. This highlights that drilling stability does not guarantee production stability.
Offshore India, National Gas Hydrate Program (NGHP) Expedition 02 [159]2015Seawater-based KCl/polymer WBDFKCl (inhibition); glycols; polymers (PHPA, PAC); sized CaCO3 (bridging).Successfully drilled and cored numerous sites in the Krishna-Godavari Basin, recovering high-quality pressure cores. Demonstrated effective hole cleaning and stability for scientific drilling.The fluid was designed for short-term coring operations, its suitability for long-term production drilling was not tested.
Ulleung Basin, East Sea (Japan Sea), South Korea (UBGH2) [160]2010KCl/glycol/polymer WBDFKCl + glycol (inhibition); polymers for rheology and filtration control.Successfully completed logging-while-drilling (LWD) and coring operations in multiple wells, confirming hydrate presence. Maintained wellbore stability for scientific objectives.Similar to other scientific expeditions, the system’s robustness for commercial-scale, long-duration drilling was not the primary focus.
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Liu, Q.; Xiao, B.; Zhuang, G.; Li, Y.; Li, Q. Instability Mechanisms and Wellbore-Stabilizing Drilling Fluids for Marine Gas Hydrate Reservoirs: A Review. Energies 2025, 18, 4392. https://doi.org/10.3390/en18164392

AMA Style

Liu Q, Xiao B, Zhuang G, Li Y, Li Q. Instability Mechanisms and Wellbore-Stabilizing Drilling Fluids for Marine Gas Hydrate Reservoirs: A Review. Energies. 2025; 18(16):4392. https://doi.org/10.3390/en18164392

Chicago/Turabian Style

Liu, Qian, Bin Xiao, Guanzheng Zhuang, Yun Li, and Qiang Li. 2025. "Instability Mechanisms and Wellbore-Stabilizing Drilling Fluids for Marine Gas Hydrate Reservoirs: A Review" Energies 18, no. 16: 4392. https://doi.org/10.3390/en18164392

APA Style

Liu, Q., Xiao, B., Zhuang, G., Li, Y., & Li, Q. (2025). Instability Mechanisms and Wellbore-Stabilizing Drilling Fluids for Marine Gas Hydrate Reservoirs: A Review. Energies, 18(16), 4392. https://doi.org/10.3390/en18164392

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