Abstract

The exploration and development of oil and gas reservoirs present significant challenges in achieving objectives such as increased reserves, enhanced production, and improved efficiency. The protection of reservoirs has been internationally recognized as a crucial technology for enabling high output with minimal investment, specifically due to the susceptibility of the drilling and completion phases to severe damage. The resulting harm significantly reduces oil and gas production and may cause drilled wells to become nonproductive, thereby hampering oil and gas field discoveries. Over the past half-century, scholars have extensively researched and developed four generations of temporary plugging-based technologies for oil and gas reservoir protection, including shielding temporary plugging, fine temporary plugging, temporary plugging with physiochemical film, and biomimetic temporary plugging. These advancements have progressively enhanced the effectiveness of reservoir protection. However, the increasing depth and complexity of oil and gas exploration and development have rendered previous technologies inadequate in providing sufficient protection, resulting in amplified risks to drilling safety such as circulation loss, sloughing, obstruction, drill pipe sticking, and blowouts. To overcome these challenges, the development of drilling and completion fluid technologies capable of forming a liquid casing during drilling has emerged as a novel solution for safeguarding oil and gas reservoirs. The successful implementation of this technology on a large scale enables the efficient development of untapped oil and gas resources, marking a breakthrough in reservoir protection. It also identifies future research directions and has practical implications for field technicians and scientific professionals.

1 Introduction

Since 1933, Fancher et al. [1] have conducted extensive research on the inconsistent air and water permeability in rock cores. In 1945, subsequent investigations from Johnson and Beeson [2] highlighted significant differences in freshwater and saltwater permeability due to the presence of clay and montmorillonite. In 1959, Monagan et al. [3] introduced the concept of oil and gas reservoir damage, sparking increased research interest in preventing damage caused by interactions between freshwater and clays. As a result, the topic of “oil and gas reservoir damage and protection” has garnered significant attention. Moreover, since 1974, the Society of Petroleum Engineers has played a vital role in organizing specialized international conferences biennially, establishing it as a pivotal research area within the field of petroleum engineering. Researchers have identified oil and gas reservoir damage as the reduction in permeability during drilling, completion, and reservoir operations [46]. Among the various factors contributing to damage, drilling and completion fluids have been recognized as crucial. These fluids, being the first to encounter the oil and gas reservoir, possess a complex composition that can lead to serious damage, negatively impacting initial productivity and subsequent operations. Consequently, researchers focused on developing drilling and completion fluid technologies to mitigate or prevent such damage, including clean brine, nonbentonite/low-bentonite polymers, shielding temporary plugging, ultra-low permeability, oil-based, and gas-based methods. Notably, the temporary plugging approach has gained wide acceptance and application, evolving into the leading “liquid casing” technology surpassing international standards [710]. These advancements have significantly enhanced our comprehension of oil and gas reservoir damage mechanisms, paving the way for more efficient and sustainable practices in industry. The structure of this article is shown in Fig. 1.

Fig. 1
The structure of this paper
Fig. 1
The structure of this paper
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2 Development and Recent Advancements in Technologies for Protecting Oil and Gas Reservoirs During Drilling and Completion Fluid Operations

In order to mitigate or prevent reservoir damage caused by drilling fluids and enhance well productivity, researchers have conducted research spanning over half a century. They have successively established four generations of temporary plugging drilling fluid technologies for reservoir protection: “shielding temporary plugging, fine temporary plugging, physicochemical membrane temporary plugging, and biomimetic temporary plugging.” These advancements have progressively improved the effectiveness of reservoir protection and demonstrated significant economic benefits. The shielding temporary plugging technology transforms adverse factors such as “pressure differentials” and “solid phase” into factors favorable for reservoir protection, effectively resolving contradictions. However, this technology is less effective in plugging large pores and tends to plug numerous smaller ones, resulting in limited reservoir protection. Fine temporary plugging technology involves adding various bridge particles of different sizes and types to the drilling fluid, expanding the plugging range, and enhancing reservoir protection. Yet, whether it is shielding temporary plugging or fine temporary plugging, accurate prediction of reservoir pore size distribution remains a challenging task. Physicochemical membrane temporary plugging successfully transitions from physical plugging to physicochemical membrane plugging, addressing the critical drawback of needing precise knowledge of reservoir pore diameter distribution patterns. However, the theory of film formation in water-based drilling fluids has yet to be substantiated by scholars. The fourth-generation temporary plugging technology incorporates biomimetics into the field of drilling fluid technology for reservoir protection. It establishes specialized biomimetic water-based drilling completion fluid technologies for reservoirs with different permeability damage characteristics. This development has triggered a wave of research on biomimetics in the drilling fluid field, marking the formation of the fourth-generation temporary plugging drilling fluid technology for reservoir protection.

2.1 Shielding Temporary Plugging for Protecting Oil and Gas Reservoirs During Drilling and Completion Fluid Operations.

During the drilling process, one of the underlying causes of reservoir damage is the intrusion of solid particles and the liquid phase from the drilling and completion fluid into the oil and gas reservoirs under positive pressure differential. This positive pressure differential refers to the difference between the column pressure of the drilling and completion fluid and the pore pressure of the reservoir. The presence of solid particles can significantly reduce the permeability of a reservoir, particularly in the vicinity of the wellbore, causing a reduction of over 90% [11]. To mitigate the issues associated with solid particle damage, Abrams et al. [12] introduced the “1/3 Bridging Rule” in 1977. This rule suggests adding bridging particles to the drilling and completion fluid, where the average particle size of these bridging particles should be equal to or slightly larger than one-third of the reservoir's pore size. Additionally, the bridging particle content should exceed 5% of the total solid content in the drilling and completion fluid. This approach effectively utilizes bridging particles to obstruct the pore throats within the reservoir, thereby preventing the intrusion of solid particles from the drilling and completion fluid into the reservoir.

In 1986, China initiated comprehensive research endeavors with the aim of protecting oil and gas reservoirs. In 1992, Luo and Pingya [13] made significant improvements to Abrams' “1/3 Bridging Rule.” Their enhancements involved the introduction of bridging particles with diameters ranging from 1/2 to 2/3 of the pore diameter (i.e., at a content exceeding 3%), fill particles with diameters approximately 1/4 of the pore diameter (i.e., at an addition rate surpassing 1.5%), and deformable particles with softening points and sizes comparable to fill particles (i.e., typically added at a rate of 1–2%). This formulation facilitated the rapid formation of a near-zero permeability barrier zone near the wellbore during drilling and completion fluid operations, effectively preventing fluid invasion into the oil and gas reservoir. Upon completion of operations, this barrier zone could be removed, enabling the resumption of fluid flow and safeguarding the integrity of the reservoir. This technique, known as “temporary plugging technology” [1417], has been successfully implemented in terms of thousands of wells across major oilfields. It has significantly increased oil and gas production rates per well while effectively addressing the technical challenges associated with protecting oil and gas reservoirs in open-hole sections with multiple pressure formations. This remarkable achievement represents a mature first-generation technology for safeguarding oil and gas reservoirs during drilling and completion of fluid operations [1822].

2.2 Fine Temporary Plugging Techniques for Protecting Oil and Gas Reservoirs During Drilling and Completion Fluid Operations.

Shielding temporary plugging techniques have been developed to protect porous sandstone oil and gas reservoirs. However, these techniques encounter challenges arising from the diverse distribution of pore throat diameters and the heterogeneity nature of the reservoirs. Furthermore, there exists a disparity in the distribution of pore throats, with a scarcity of larger pore throats and a prevalence of smaller ones. Additionally, pore throat diameters of various sizes contribute differently to production, with larger pore throats having a more significant impact while microscale pore throats have minimal or negligible contributions [23]. The selection of bridging particles, fill particles, and deformable particles in shielding temporary plugging techniques is typically based on the average pore throat diameter of the reservoir. Consequently, the shielding temporary plugging zone may not effectively seal the larger pore throats that significantly contribute to production, while efficiently blocking smaller pore throats that do not participate in fluid flow. Consequently, the closure of these smaller pore throats carries minor practical significance. Despite shielding temporary plugging techniques demonstrating improvements in single-well production when compared to previous methods, their effectiveness in protecting oil and gas reservoirs remains restricted.

In response to this challenge, Guancheng et al. [24] introduced innovative strategies in 1999 to enhance shielding temporary plugging techniques and enable shielding temporary plugging in oil and gas reservoirs with a broad range of pore diameters. These approaches were successfully executed in three wells located in the Da-Wan-Qi area of China's Tarim Basin. Comparisons with prior protection techniques revealed a remarkable reduction of over 98% in the average coefficient of skin factor.

In 2003, Tongtai et al. [25] conducted further in-depth research, expanding on the previous work. They proposed a specific approach to achieve broad-spectrum temporary plugging in oil and gas reservoirs with a wide range of pore diameter distributions. This novel approach takes into account both the average and the maximum pore throat diameter of the reservoir to determine the particle sizes of bridging particles and fill particles. By incorporating these factors, the method accounted for the reservoir's heterogeneity and the varying contributions of pore throats of different sizes to production. Notably, this technique has been successfully applied in numerous oilfields, yielding favorable results.

Building upon insights from Guoxin et al. [19], Zhang and Jienian, Lijun et al., and Kaeuffer [11,26,27] integrated unique approaches proposed by Dick et al. [28,29], Chellappah and Aston [30], and Hands et al. [31] to develop a graphical method for optimizing particle sizes of temporary plugging agents, named the “Ideal Fill Technique.” This method, based on ideal fill theory, has been successfully employed in various oilfields, leading to significantly enhanced single-well production compared to previous shielding temporary plugging techniques.

Broad-spectrum temporary plugging and ideal fill techniques represent notable advancements in fine temporary plugging methods. The work of Guancheng et al. [24] has led to the development of innovative techniques such as fractal geometry temporary plugging [32], fiber-based temporary plugging [33], D50 temporary plugging [34], and multistage bridging [35]. These techniques overcome the drawbacks of previous shielding temporary plugging methods by effectively sealing larger pore throats while minimizing excessive plugging of microscale pore throats. These refined techniques represent the second generation of temporary plugging, and mark a significant shift toward improving the protection of oil and gas reservoirs during drilling and completion fluid operations.

2.3 Temporary Plugging With Physiochemical Film for Protecting Oil and Gas Reservoirs During Drilling and Completion Fluid Operations.

The successful implementation of shielding temporary plugging and fine temporary plugging techniques relies on accurate prediction of pore size distribution in the oil and gas reservoir. However, obtaining precise pore size distribution by conducting comprehensive analysis and testing of the entire core sections of reservoir wells is practically unfeasible. This limitation significantly affects the effectiveness of oil and gas reservoir protection, making it a critical drawback of first and second-generation protection technologies. To overcome this challenge, researchers such as Jiang et al. [36] and Sun [37] have devised solutions using a combination of physical and chemical sealing methods, namely, the oil film method [36] and the film-forming method [37]. These innovative techniques allow for effective reservoir protection without the need for matching pore throat sizes. The oil film method and the film-forming method have emerged as noteworthy examples of physiochemical film-based temporary plugging techniques for safeguarding oil and gas reservoirs.

2.3.1 Broad-Spectrum “Oil Film” Drilling and Completion Fluid Technology.

Since the initial proposal of the shale film theory by Staverman in the 1950s [32], subsequent researchers have conducted extensive investigations in this area. Distinguished scholars, such as Staverman [38], Van et al. [39], Ewy and Stankovich [40], Zhang et al. [41], and Osuji et al. [42], have contributed significantly to this field. Building upon the foundation of the equilibrium activity of oil-in-water emulsion drilling and completion fluid theory, it has been postulated that the formation of a hydrophobic oil film on the wellbore wall can act as a protective barrier. This oil film prevents direct contact between the wellbore and the drilling and completion fluid, thereby safeguarding the oil and gas reservoir.

Jiang et al. [43] have made significant strides in the development of an oil film temporary plugging agent. Their pioneering work, published in 2005, 2006, and 2010, highlighted the impressive capabilities of this agent. It possesses the ability to soften, deform, and effectively wedge itself into the pore throats under specific temperature and pressure differentials. Driven by the power of electrostatic and chemical bonding forces, it rapidly forms a resilient and low-permeability “oil film” temporary plugging barrier near the wellbore. This barrier effectively prevents the intrusion of drilling and completion fluid into the oil and gas reservoir. The development of this agent represents a significant milestone in the transition from physical temporary plugging to physiochemical film temporary plugging, eliminating the need for precise prediction of pore size distribution. Upon completion, the oil film barrier can be easily removed through techniques such as perforation, backflow, or dissolution, thereby restoring fluid flow and ushering in a new era of oil and gas reservoir protection [36,43,44].

The implementation of this technique is uncomplicated, requiring only the addition of 3% of “oil film” temporary plugging agent with the broad-spectrum coverage to the upper drilling fluid system. This simple adjustment effectively transforms the drilling and completion fluid system into a protection system, providing an “oil film” shield for oil and gas reservoirs. Extensive testing of this technique has been carried out in over 1000 wells across diverse oilfields in China, resulting in significant enhancements in both drilling efficiency and safety. Additionally, the technique has demonstrated a remarkable increase of more than 2.7 times in oil recovery indices [36], unequivocally proving the superior protective effects when compared to fine temporary plugging technology.

2.3.2 Film-Forming Drilling and Completion Fluid Technology.

Film-forming drilling and completion fluid technology, akin to oil film drilling and completion fluid, is developed to safeguard oil and gas reservoirs by creating a substance that resembles a film on the wall of the wellbore.

The development of film-forming drilling and completion fluid technology has been guided by the film-forming theories established by researchers such as Staverman [38], Van et al. [39], Ewy and Stankovich [40], Zhang et al. [41], and Osuji et al. [42]. In addition, the development was inspired by the advancements in nondamaging drilling and completion fluid systems, such as the DMC2000 fluid by EDIT [4550]. Furthermore, Schlemmer et al. [51] and Mody et al. [52] explored the film efficiency of various drilling and completion fluid-shale systems, revealing that silicates are the most effective materials for enhancing film efficiency, with values ranging from 55% to 85%. Mody et al. [52] also introduced the concept of isolation membranes in 2002, highlighting the significance of shale film formation in water-based drilling and completion fluid systems within the petroleum industry.

Further investigation conducted by Lei [53] and Pu et al. [54] utilized the concentration polarization theory and identified that isolation membranes are formed from semi-permeable membranes through processes such as concentration diffusion or repeated substance deposition. As a result, there is a significant decrease or complete cessation of free water permeability in the drilling and completion fluid on the isolation membranes.

Sun [37] made remarkable advancements in film-forming techniques for water-based drilling and completion fluid systems by introducing the organosilicate semi-permeable membrane treatment agent BTM-2 and isolation membrane agents CMJ-1 and CMJ-2. Extensive field experiments conducted in multiple wells in China have verified the significant effectiveness of these innovations in protecting oil and gas reservoirs. In addition, He et al. [55], Su et al. [56], Wu et al. [57], Bai and Pu [58], and other researchers [59,60] have independently developed film-forming agents and film-forming drilling and completion fluid systems. These systems have been successfully applied in field operations.

Both oil film and film-forming temporary plugging techniques rely on the physical and chemical interactions to create a barrier and shield the wellbore and drilling fluid from the reservoir. These techniques do not require precise knowledge of the reservoir's pore size and distribution, overcoming the limitations of traditional shielding temporary plugging and fine temporary plugging methods. This research area [61,62] has contributed to the evolution of oil and gas reservoir protection during drilling and completion fluid operations, transitioning from the phase of physical packing using inert particles to the third generation of physiochemical film temporary plugging.

2.4 Biomimetic Temporary Plugging for Protecting Oil and Gas Reservoirs During Drilling and Completion Fluid Operations.

Advances in oil film and film-forming techniques have resulted in the development of physiochemical films for temporary plugging, overcoming the need for precise knowledge of the pore throat diameter distribution in oil and gas reservoirs. However, the ability of water-based drilling and completion fluids to form high-efficiency films on the rock surfaces, such as sandstone, has not been confirmed by researchers [3842,63,64]. Even when films are formed, their efficiency is lower than that of oil-based drilling and completion fluids [39,65,66]. Moreover, the formation of films typically requires a certain amount of time, and high-pressure differentials (e.g., pressure fluctuations, multiple pressure formations) can easily disrupt the film, rendering the protection of oil and gas reservoirs ineffective. Though physiochemical films represent a temporary plugging solution, there is still a substantial gap in achieving “ultra-low” or “zero” damage. To address this challenge, Jiang et al. [6773] took inspiration from biomimetics and incorporated it into the theory of protecting oil and gas reservoirs with drilling and completion fluids. By tailoring their water-based technologies to the specific characteristics of varying permeabilities, these biologically inspired solutions have achieved notable success in protecting reservoirs and have become the fourth generation of drilling and completion fluid technologies. These advancements have been validated and widely applied in major oilfields, presenting significant progress in reservoir protection.

2.4.1 Super-Amphiphobic Low-Permeability Oil and Gas Reservoir Protection Technology.

Jiang et al. [6769,7476] drew inspiration from the super-amphiphobic surface found in the peristome region of Nepenthes (Fig. 2), which effectively prevents oil and water adsorption and infiltration. They have successfully developed super-amphiphobic agents (Figs. 35) that exhibit similar properties. These agents can create micro-nano papillae structures on the rock surfaces of oil and gas reservoir wellbores, thereby reducing the surface energy of the rocks.

Fig. 2
Super-amphiphobic surface in the peristome region of nepenthe [67]
Fig. 2
Super-amphiphobic surface in the peristome region of nepenthe [67]
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Fig. 3
Transmission electron microscopy of super-amphiphobic treatment agent [68]
Fig. 3
Transmission electron microscopy of super-amphiphobic treatment agent [68]
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Fig. 4
Original surface structure of the rock surface [68]
Fig. 4
Original surface structure of the rock surface [68]
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Fig. 5
Micro-nano papillae structures of the rock surfaces [68]
Fig. 5
Micro-nano papillae structures of the rock surfaces [68]
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The direction of capillary force is governed by the capillary force equation ΔP=2σcosθr, which states that when the contact angle θ exceeds 90 deg, the value of cos θ becomes negative, resulting in a reversal of the capillary force ΔP from positive to negative. This reversal transforms capillary suction into capillary resistance and prevents the infiltration of oil and water into the rock core. It is particularly significant for low-permeability and ultra-low-permeability oil and gas reservoirs, where the smaller curvature radius r further enhances the effect. As a result, this approach can effectively address the challenges associated with damage in such reservoirs.

Laboratory evaluations have shown that the addition of 3% super-amphiphobic agent into the drilling and completion fluid system significantly increases the plugging rate and permeability restoration value of low-permeability and ultra-low-permeability rock cores with pore sizes within the range of 100 × 10−3µm2. The plugging rate and permeability restoration value have exceeded 92% and 95%, respectively. These results provide strong evidence for the excellent protective properties of the super-amphiphobic agent in preventing damage to low-permeability and ultra-low-permeability oil and gas reservoirs caused by drilling and completion fluids. In practical applications, the incorporation of 3% super-amphiphobic agent in the upper drilling and completion fluid system effectively transforms it into a super-amphiphobic-type protection system. This approach has been widely adopted in major oilfields and yield remarkable outcomes. The daily production after well completion has shown an increase of 2.6 times compared to nearby wells, indicating the successful protection of low-permeability and ultra-low-permeability oil and gas reservoirs.

2.4.2 Biologically Inspired Permeable Oil and Gas Reservoir Protection Technology.

The hydrophobic and self-cleaning properties of lotus leaves have been a valuable source of inspiration for the development of biomimetic superhydrophobic membrane materials. Jiang et al. [7072,77] have utilized this natural inspiration to create biologically inspired membranes for oil and gas reservoir protection. Through their research, they have successfully developed superhydrophobic agents that generate biomimetic superhydrophobic films when applied to the wellbore. These films act as barriers to prevent the infiltration of liquid and solid particles from drilling and completion fluids, thereby safeguarding medium-permeability oil and gas reservoirs.

The performance of biomimetic superhydrophobic membranes in safeguarding oil and gas reservoirs was evaluated through laboratory assessments utilizing the upper polymer-based drilling and completion fluids and medium-permeability rock cores of China 33-531-4 well. The findings revealed substantial enhancements in plugging rates and permeability restoration values when implementing this technology compared to traditional drilling fluids. Moreover, a synergistic effect was observed when combining super-amphiphobic agents with superhydrophobic agents. A concentration of superhydrophobic agent exceeding 2% in the system achieved a plugging rate of over 90%, with minimal incremental improvement beyond this threshold. Successful deployments of this technology in medium-permeability oil and gas fields have demonstrated remarkable results. A comparison with conventional wells revealed an improvement in the reduction of the skin factor coefficient by more than 99%. Under identical conditions, the meters of oil production per equivalent wellbore increased by 54–103%. An exemplary instance of this achievement is evident in China's Dagang oilfield, where the experimental wells accomplished self-jet oil production.

2.4.3 Synergistic Enhancement for High-Permeability Oil and Gas Reservoir Protection Technology.

For high-permeability and ultra-high-permeability oil and gas reservoirs, the application of biofilm protection technology can lead to membrane damage due to significant positive pressure differentials. Moreover, solid particle blockage issues can pose a challenge for super-amphiphobic technology. To address these challenges, Jiang et al. [78,79] drew inspiration from the layered structure of mud and shells observed in brickwork, as well as the natural protection mechanisms of soft-bodied organisms [80]. They combined biofilm and ideal packing technology to transform large pore throats into small pore throats, which allowed for the establishment of a biofilm on the small pore throats. This synergistic approach can effectively protect high-permeability and ultra-high-permeability oil and gas reservoirs [81,82].

The implementation of this technology involves the utilization of upper drilling and completion fluid, coupled with a (1–2)% film-forming agent and a (2–3)% ideal packing agent. Permeability damage evaluations were conducted using amphoteric ion polymer mud during on-site applications, revealing that the addition of 2% film-forming agent and 3% ideal packing agent to the drilling fluid resulted in a permeability restoration value of 93.5% for high-permeability cores (initial permeability of 354.8 × 10−3µm2). The application of synergistic enhancement technology in high-permeability oil fields has demonstrated a notable increase in individual well production, surpassing that of other techniques by 3.2 times on average.

3 Emergence of Liquid Casing for Oil and Gas Reservoir Protection Technology

With the increasing complexity of geological conditions in exploration and development become increasingly complex, the drilling risks have become more prominent in severe reservoir damage. These risks include circulation loss, sloughing, and high frictional resistance, which are often caused by higher temperatures and pressures, as well as diverse physical and chemical properties. The previously developed fourth-generation oil and gas reservoir protection technologies are no longer fully effective in addressing these evolving challenges. In response to this problem, researchers such as Jiang Guancheng continued to draw inspiration from nature. By utilizing the aforementioned super-amphiphobic agents in combination with biomimetic solid wall agents and bonding lubricants, they have developed a water-based drilling and completion fluid system that can form a “liquid casing” during drilling operations. This innovative approach seamlessly integrates the objectives of oil and gas reservoir protection, leak prevention, plugging prevention, collapse prevention, friction reduction, and other key considerations, providing a comprehensive solution to the complex challenges faced in drilling operations.

The mechanism of “liquid casing” consists of two main components (Figs. 6 and 7): first, during the complex downhole conditions, drilling fluids interact with reservoirs in a physical-chemical manner, instantaneously filling and plugging pores, fissures, and cavities, creating a stable, dense, high-strength sealing zone that resembles a “casing” around the wellbore. Subsequently, during well completion, this “liquid casing” is removed, allowing adsorbed hydrocarbons to desorb into a free state, thereby expanding the permeability channels for hydrocarbon flow.

Fig. 6
Dispensing drilling fluid organization reservoir damage
Fig. 6
Dispensing drilling fluid organization reservoir damage
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Fig. 7
A stable oil and gas seepage channel is formed after completion
Fig. 7
A stable oil and gas seepage channel is formed after completion
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3.1 Development of Liquid Casing Technology.

During the drilling process, a specially formulated drilling and completion fluid, is utilized to fill the voids, fractures, and cavities within the wellbore of the oil and gas reservoir [83,84]. This fluid consists of specialized treatment agents, which results in the formation of a thin, compact, smooth, impact-resistant, erosion-resistant, and casing-like high-strength sealing zone along the wellbore wall [85]. This sealing zone acts as a barrier, effectively preventing direct contact between the drilling and completion fluid and the oil and gas reservoir. The implementation of this technology can effectively overcome the limitations associated with the previous four generations of reservoir protection technologies [80]. It can thus achieve the integrated objectives such as “protecting the oil and gas reservoir and increasing production” and “preventing and controlling drilling risks to ensure safe drilling.”

3.1.1 Enhancing Density and Sealing Strength of Liquid Casing.

To assess the density and sealing strength of the liquid casing, shale rock cores with similar initial mechanical properties were meticulously chosen for analysis. These rock cores were subjected to various solutions, including distilled water, a 3% solid wall agent solution, and a 10% KCl solution, and were immersed for 48 h. The resulting changes in the rock core's strength were analyzed to evaluate the effectiveness of the liquid casing [40,75]. The data collected were compiled in Table 1, and the findings indicated that the compressive strength, elastic modulus, and cohesion of the rock cores experienced varying degrees of reduction when immersed in different solutions [85,86]. The rock cores immersed in the solid wall agent solution exhibited the smallest decrease in cohesion, indicating the formation of a liquid casing on the rock core's surface while preserving its compressive strength and cohesion (Figs. 8 and 9).

Fig. 8
Surface morphology of mudstone rock fragments before and after treatment with the solid wall agent: (a) rock fragment before treatment and (b) rock fragment after immersion in the solid wall agent forming the liquid casing [85]
Fig. 8
Surface morphology of mudstone rock fragments before and after treatment with the solid wall agent: (a) rock fragment before treatment and (b) rock fragment after immersion in the solid wall agent forming the liquid casing [85]
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Fig. 9
Formation of liquid casing on illite rock core: (a) original illite rock core, (b) appearance of the rock core after immersion in a strong inhibitive solution (7% KCl + 2% polyether amine) for 24 h, and (c) illite rock core after immersion in a 3% solid wall agent solution for 24 h, forming the liquid casing [86]
Fig. 9
Formation of liquid casing on illite rock core: (a) original illite rock core, (b) appearance of the rock core after immersion in a strong inhibitive solution (7% KCl + 2% polyether amine) for 24 h, and (c) illite rock core after immersion in a 3% solid wall agent solution for 24 h, forming the liquid casing [86]
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Table 1

Mechanical performance testing of shale rock cores immersed in different solutions [40,75]

Mechanical parametersConfining pressure (MPa)Untreated core+3% clear water+3% wall fixing solution+10% KCl solution
Compressive strength (MPa)0163.6788.17119.254117.00
10214.60165.93171.84173.00
20244.07198.62208.96222.00
Modulus of elasticity (GPa)024.6716.0318.0520.69
1035.3519.1021.7119.86
2024.0221.7419.8823.83
Cohesion (MPa)31.388.6118.1714.29
Mechanical parametersConfining pressure (MPa)Untreated core+3% clear water+3% wall fixing solution+10% KCl solution
Compressive strength (MPa)0163.6788.17119.254117.00
10214.60165.93171.84173.00
20244.07198.62208.96222.00
Modulus of elasticity (GPa)024.6716.0318.0520.69
1035.3519.1021.7119.86
2024.0221.7419.8823.83
Cohesion (MPa)31.388.6118.1714.29

3.1.2 Modifying Wettability and Reversing Capillary Forces.

The wettability of the wellbore rock surface plays a crucial role in ensuring the high quality of liquid casing. Whether the surface is hydrophilic or hydrophobic, the capillary self-suction effect can lead to the infiltration of water and oil (or hydrophobic substances) into the rock, resulting in reservoir damage and drilling safety risks. To mitigate these risks, it is possible to alter the wettability of the wellbore surface by adsorbing super-amphiphobic agents and creating nano-microscale rough structures of liquid casing. As illustrated in Fig. 10, this approach serves to reduce the surface free energy and reverse the capillary forces from suction to resistance, thereby effectively preventing damage and reducing risks associated with drilling.

Fig. 10
Oil and water contact angles on the wellbore surface under different concentrations of super-amphiphobic agents: (a) water droplet state at 0% concentration, (b) oil droplet state at 0% concentration, (c) water droplet state at 3% concentration, and (d) oil droplet state at 3% concentration
Fig. 10
Oil and water contact angles on the wellbore surface under different concentrations of super-amphiphobic agents: (a) water droplet state at 0% concentration, (b) oil droplet state at 0% concentration, (c) water droplet state at 3% concentration, and (d) oil droplet state at 3% concentration
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3.1.3 Lubrication Performance of Liquid Casing.

Improving drilling efficiency while minimizing reservoir damage and mitigating drilling safety risks can be achieved through the enhancement of lubrication and reducing friction. A comparative analysis was conducted on the lubrication performance of different lubricants added to a 4% base slurry. The results, presented in Table 2, demonstrate that the bonding lubricant was the most favorable lubrication effect in the base slurry, resulting in a remarkable reduction of up to 90% in the lubrication coefficient after aging. Moreover, this lubricant effectively addressed resolved the common issue of lubricant foaming.

Table 2

Extreme pressure lubrication test results of different lubricants in a 4% base slurry

SampleBefore agingPost-aging
Friction coefficientFriction coefficient reduction rate (%)Foaming conditionFriction coefficientFriction coefficient reduction rate (%)Foaming condition
4% base pulp0.54Not blistering0.52Not blistering
4% base pulp + 1% PF-lube (Zhanjiang, China)0.3240.7%Slight foaming0.3238.5%Obvious blistering
4% base pulp + 1%CX-300H (Zhanjiang, China)0.1670.4%Severe blistering0.1571.2%Severe blistering
4% base pulp + 1%PF-lube (Tianjin, China)0.3142.6%Slight blistering0.1375.0%Obvious blistering
4% base pulp + 1% Grydis Company0.2259.3%Blistering0.1178.8%Foaming
4% base pulp + 1% DFL (US)0.1081.5%Slight blistering0.0884.6%Slight blistering
4% base pulp + 1% bonding lubricant0.0983.3%Not blistering0.0590.4%Nonfoaming
SampleBefore agingPost-aging
Friction coefficientFriction coefficient reduction rate (%)Foaming conditionFriction coefficientFriction coefficient reduction rate (%)Foaming condition
4% base pulp0.54Not blistering0.52Not blistering
4% base pulp + 1% PF-lube (Zhanjiang, China)0.3240.7%Slight foaming0.3238.5%Obvious blistering
4% base pulp + 1%CX-300H (Zhanjiang, China)0.1670.4%Severe blistering0.1571.2%Severe blistering
4% base pulp + 1%PF-lube (Tianjin, China)0.3142.6%Slight blistering0.1375.0%Obvious blistering
4% base pulp + 1% Grydis Company0.2259.3%Blistering0.1178.8%Foaming
4% base pulp + 1% DFL (US)0.1081.5%Slight blistering0.0884.6%Slight blistering
4% base pulp + 1% bonding lubricant0.0983.3%Not blistering0.0590.4%Nonfoaming

3.2 Evaluation of the Performance of Liquid Casing in Drilling and Completion Fluids.

The composition of liquid casing water-based drilling and completion fluid is based on biomimetic solid wall agents, super-amphiphobic agents, and bonding lubricants. The fundamental formulation includes 0.15% slurry, 2–3% wall cement, 1–2% bonding lubricant, 2–3% super-amphiphobic agent, 1–3% fluid loss reducer, 7% KCl, and 1–3% rheology modifier with barite (i.e., adjusted to achieve the desired density). A comprehensive comparison was conducted to compare the performance of this liquid casing formulation with typical oil-based drilling and completion fluids.

3.2.1 Rheological Properties, Filtration Control, and Lubrication Performance.

Compared to typical oil-based drilling and completion fluids, the liquid casing water-based drilling and completion fluid exhibits superior rheological properties, comparable filtration control, lower filter cake viscosity, and improved lubrication performance, as shown in Table 3.

Table 3

Rheological properties and filtration control of drilling and completion fluid systems

Type of drilling and completion fluidDensity (g/cm3)AV (mPa · s)PV (mPa · s)YP (Pa)GEL (Pa/Pa)Fluid loss (ml)Coefficient of filter cake viscosity
APIHTHP
Liquid casing water-based drilling and completion fluid1.39261792/40.5/0.54.60.023
Typical oil-based drilling completion fluid1.39302372.5/70.5/0.54.50.025
Type of drilling and completion fluidDensity (g/cm3)AV (mPa · s)PV (mPa · s)YP (Pa)GEL (Pa/Pa)Fluid loss (ml)Coefficient of filter cake viscosity
APIHTHP
Liquid casing water-based drilling and completion fluid1.39261792/40.5/0.54.60.023
Typical oil-based drilling completion fluid1.39302372.5/70.5/0.54.50.025

Note: Aging condition 150 °C, 16 h; high-temperature and high-pressure filtration loss measurement temperature 150 °C, pressure difference 3.5 MPa; typical oil-based drilling and completion fluid formula: 282 ml white oil + 3% gellant (MOGEL) + 3% main milk + 3% auxiliary milk + 5% bituminous resin (MOLSF) + 5% oil-based drilling fluid plugging agent (MORLF) + 5% calcium oxide (MOALK) + 18 ml 25% CaCl2 brine) + barite. AV: apparent viscosity; PV: plastic viscosity; YP: yield point; API: American Petroleum Institute; and HTHP: high temperature and high pressure filtration.

3.2.2 Inhibitory.

The rolling recovery rate experiment was conducted using shale cuttings from a highly prone sloughing section of a shale gas well in the Weiyuan County, China. The findings, as presented in Table 4, demonstrate that the liquid casing water-based drilling and completion fluid exhibited higher first and second recovery rates as compared to typical oil-based drilling and completion fluids. Furthermore, the liquid casing fluid demonstrated better performance than currently available high-performance water-based drilling and completion fluids, especially in terms of recovery rates.

Table 4

Comparison of cuttings recovery rates (aging temperature at 150 °C and aging time at 16 h)

Pound numberRecovery rate (%)Other high-performance water-based drilling and completion fluids (pulp)Typical oil-based drilling and completion fluidsLiquid casing water base drilling and completion fluid
12-1-B5Primary recovery rate90.993.595.6
Secondary recovery rate46.85079
12-1-B6Primary recovery rate94.49898.2
Secondary recovery rate83.295.395.6
The 12-1-6Primary recovery rate8094.898.7
Secondary recovery rate77.493.996.7
Weiyuan shale gas wellPrimary recovery rate88.782.396.3
Changning shale gas wellPrimary recovery rate88.697.998.7
Pound numberRecovery rate (%)Other high-performance water-based drilling and completion fluids (pulp)Typical oil-based drilling and completion fluidsLiquid casing water base drilling and completion fluid
12-1-B5Primary recovery rate90.993.595.6
Secondary recovery rate46.85079
12-1-B6Primary recovery rate94.49898.2
Secondary recovery rate83.295.395.6
The 12-1-6Primary recovery rate8094.898.7
Secondary recovery rate77.493.996.7
Weiyuan shale gas wellPrimary recovery rate88.782.396.3
Changning shale gas wellPrimary recovery rate88.697.998.7

Note: Typical oil-based drilling and completion fluid formula: 282 ml white oil + 3%MOGEL + 3% main milk + 3% auxiliary milk + 5%MOLSF + 5%MORLF + 5%MOALK + 18 ml 25%CaCl2 brine) + barite.

3.2.3 Rock Core Strength.

Based on Table 5, it can be observed that the compressive strength of rock cores immersed in liquid casing water-based drilling and completion fluid is higher than that of typical oil-based drilling and completion fluids and other high-performance water-based drilling and completion fluids. This indicates that the implementation of liquid casing water-based drilling and completion fluid enhances the strength of the rock cores, with a progressive enhancement observed as time elapses.

Table 5

Comparison of compressive strength of rock cores immersed in different drilling and completion fluid systems (immersion temperature at 120 °C and pressure at 3.5 MPa)

Rock core strength (MPa)Typical oil-based drilling completion fluidOther high-performance water-based drilling and completion fluids (slurry)Liquid casing water base drilling and completion fluid
Soak for 3 days4.743.14.94
Soak for 10 days2.190.672.59
Rock core strength (MPa)Typical oil-based drilling completion fluidOther high-performance water-based drilling and completion fluids (slurry)Liquid casing water base drilling and completion fluid
Soak for 3 days4.743.14.94
Soak for 10 days2.190.672.59

Note: Rock core original strength 8.89 MPa and 1.82 MPa after soaking in water for 3 min. Typical oil-based drilling and completion fluid formula: 282 ml white oil + 3%MOGEL + 3% main milk + 3% auxiliary milk + 5%MOLSF + 5%MORLF + 5%MOALK + 18 ml 25%CaCl2 brine) + barite.

3.2.4 Strategies for Reservoir Protection.

Contamination experiments were conducted on the end faces of rock cores using both liquid casing water-based drilling and completion fluid, as well as typical oil-based drilling and completion fluid [63,64,87]. The permeability restoration values were found to be 96.5% and 94.4%, respectively (Table 6). Additionally, computed tomography scanning was utilized to visualize the changes in rock core porosity and reservoir storage space parameters before and after contamination, as presented in Table 7. It was observed that both drilling and completion fluids caused a reduction in internal porosity and reservoir storage space. However, the reduction in porosity and storage space following contamination with liquid casing water-based drilling and completion fluid was smaller in comparison to typical oil-based drilling and completion fluid, indicating a superior effectiveness in preserving the reservoir.

Table 6

Comparison of permeability restoration values of rock cores in different drilling and completion fluid systems (contamination temperature at 120 °C and pressure at 3.5 MPa) [63]

Drilling and completion liquid systemsDrilling and completion fluid density (g/cm3)Core permeability recovery value (%)
Liquid casing water base drilling and completion fluid1.3996.5
Typical oil-based drilling completion fluid1.3994.4
Drilling and completion liquid systemsDrilling and completion fluid density (g/cm3)Core permeability recovery value (%)
Liquid casing water base drilling and completion fluid1.3996.5
Typical oil-based drilling completion fluid1.3994.4
Table 7

Comparison of reservoir storage space parameters before and after rock core contamination [64]

StateAverage pore radius (µm)Average throat radius (µm)Average laryngeal length (µm)Average pore–throat ratioAverage pore volume (µm)Average throat volume (µm)Maximum coordination number (connectivity)
Original rock core29.0215.6655.260.501.30 × 1062.81 × 1057
Liquid casing water base drilling and completion fluid contamination27.6613.4050.010.441.29 × 1062.56 × 1054
Typical oil-based drilling and completion fluid contamination16.2210.3240.110.191.20 × 1062.46 × 1052
StateAverage pore radius (µm)Average throat radius (µm)Average laryngeal length (µm)Average pore–throat ratioAverage pore volume (µm)Average throat volume (µm)Maximum coordination number (connectivity)
Original rock core29.0215.6655.260.501.30 × 1062.81 × 1057
Liquid casing water base drilling and completion fluid contamination27.6613.4050.010.441.29 × 1062.56 × 1054
Typical oil-based drilling and completion fluid contamination16.2210.3240.110.191.20 × 1062.46 × 1052

3.2.5 Lubrication Performance.

The lubrication performance was evaluated by conducting extreme pressure lubrication tests and four-ball friction tests, including the analysis of adsorbed film thickness, prior to and after the addition of 2% bonding lubricant. The results revealed that the liquid casing water-based drilling and completion fluid exhibited the lowest friction coefficient (Table 8). Moreover, the steel ball surfaces exhibited fewer wear marks and smoother characteristics (Fig. 11(b)), and the adsorbed film thickness on the steel ball surfaces measured 100 nm or more (Fig. 12). This improved lubrication performance can be attributed to the bonding lubricant present in the liquid casing water-based drilling and completion fluid, which effectively adsorbed onto the surfaces of the metal drilling tools, forming a thick and durable lubricating film. This film significantly reduces frictional wear on the steel ball, ultimately enhancing the lubrication performance of the drilling and completion fluid.

Fig. 11
Comparison of ball spot size: (a) conventional efficient water-based drilling and completion fluids and (b) liquid casing drilling and completion fluid
Fig. 11
Comparison of ball spot size: (a) conventional efficient water-based drilling and completion fluids and (b) liquid casing drilling and completion fluid
Close modal
Fig. 12
Comparison of film thickness and element content on steel ball surface: (a) Fe element and (b) element C
Fig. 12
Comparison of film thickness and element content on steel ball surface: (a) Fe element and (b) element C
Close modal
Table 8

Results of extreme pressure lubrication tests for different samples

SamplesCoefficient of frictionFriction coefficient reduction rate (%)
Clean water0.34
Conventional high-efficiency water-based drilling completion fluid0.1944.1
Liquid casing water-based drilling and completion fluid0.1070.6
SamplesCoefficient of frictionFriction coefficient reduction rate (%)
Clean water0.34
Conventional high-efficiency water-based drilling completion fluid0.1944.1
Liquid casing water-based drilling and completion fluid0.1070.6

3.3 Field Application Results.

The liquid casing water-based drilling and completion fluid technology has proven to be highly successful in 1000 complex oil and gas wells across various regions, including Zhaotong shale gas, Bohai Bay shale oil, Sulige and Songliao basins tight gas, Junggar Basin tight oil, and Shanxi coalbed methane in China, as well as in Chad. In comparison with the oil-based drilling and completion fluids and other high-performance water-based drilling and completion fluids utilized the same blocks, the liquid casing water-based drilling and completion fluid exhibits significant advantages in terms of inhibition, wellbore stability, filtration control, rheological properties, lubrication, and environmental friendliness. It significantly enhances oil and gas production from the wells and has demonstrated remarkable overall performance. Specifically, it has resulted in an average reduction of 82.6% in sloughing incidents, 80.6% in circulation loss, and 80.7% in wellbore blockage and drill pipe sticking under complex conditions. Additionally, mechanical drilling speed has increased by 32.8%, and production has increased by over 1.5 times. Schlumberger has introduced and implemented the technology in horizontal tight gas wells in China's Yan'an Baota, Zichang County, and Ansai areas. The application has led to an average drilling speed improvement of over 30.1%, a comprehensive cost reduction of 42.3% in drilling and completion fluids, and an increase in production of over 1.6 times. Through field tests and its widespread implementation, the technology has proved its efficacy in attaining the crucial objectives of reservoir protection and risk mitigation. As a result, it has emerged as a pivotal and highly efficient core technology for the development of complex oil and gas resources, bolstering scalability, efficiency, and environmental considerations. Several typical case studies are presented in the following section.

3.3.1 Reservoir Protection and Significant Increase in Oil and Gas Well Production.

Prior to 2015, the application of alternative drilling and completion fluid technologies in nearly 100 coalbed methane wells in the Zhengzhuang and Fanzhuang blocks of the Qinshui Basin, Shanxi, China, resulted in subpar production rates and incurred financial losses. However, since the implementation of liquid casing drilling and completion fluid in 2016, the daily production of individual wells experienced a more than three times increase, essentially reversing the previous financial losses into profitability. Consequently, this technology has been widely promoted and executed, providing significant impetus for the development of China's largest coalbed methane field, which achieves an annual production of over 4 billion cubic meters.

3.3.2 Enhancement of Wellbore Quality and Ensured Drilling Safety Through Real-Time Casing.

In 2018, advanced water-based drilling and completion fluids were utilized in the drilling of three horizontal wells in the Zhaotong shale gas field to promote environmental protection and cost reduction. However, these wells encountered severe incidents, such as well collapse, stuck pipe, and high torque pressure, making it impossible for further drilling without switching to oil-based drilling and completion fluids. To address these challenges, a mid-drilling switch to oil-based drilling and completion fluids was made to continue the operations. Nevertheless, in 2019, the liquid casing technology was implemented in three additional horizontal wells with even more complex geological conditions. This application effectively mitigated drilling safety risks and laid the foundation for the widespread adoption of the technology in complex oil and gas wells throughout the country. As a result, the previous reliance on “costly and environmentally polluting” oil-based drilling and completion fluids was successfully replaced with water-based alternatives, enabling the smooth completion of drilling operations. Notable achievements were witnessed in prominent oil and gas production areas, such as the Bohai Oilfield, the largest crude oil production base in China with an annual output exceeding 30 million tons; the Bozhong 19-6 condensate gas field with reserves reaching billions of cubic meters; the Mahu Oilfield, the world's largest conglomerate reservoir oilfield with an annual production exceeding 3 million tons; and the Linxing–Shenfu large-scale tight gas field in China with an annual production of 3 billion cubic meters. The successful implementations of liquid casing technology in these fields are instrumental in the efficient development of these substantial oil and gas reservoirs, simultaneously ensuring environmental protection and cost savings.

4 Trends and Conclusions in the Development of Oil and Gas Reservoir Protection With Drilling and Completion Fluid Technology

The implementation of oil and gas reservoir protection techniques has proven to be a highly effective method for increasing reserves, production, and overall efficiency. Extensive research conducted by both national and international experts over the past 50 years has resulted in significant achievements in the reduction of reservoir damage and improved economic benefits. However, with the growing complexity of oil and gas exploration and development, the challenges faced in maintaining reservoir protection and mitigating drilling risks have become unprecedented. This study presents an overview of the current research status and combines it with future industry trends to elucidate the development of oil and gas reservoir protection through the use of drilling and completion fluid technology.

4.1 Strengthening Research on Liquid Casing Drilling and Completion Fluid Technology.

Utilizing a thorough analysis of advanced drilling and completion fluid technologies on a domestic and international scale, combined with the latest theories across various disciplines, Jiang Guancheng's group at China University of Petroleum (Beijing) has pioneered the theory and technology of liquid casing drilling and completion fluid. This innovative approach has proven successful in tackling technical challenges that other advanced technologies have failed to address in various complex oil and gas reservoirs. The integration of reservoir protection and drilling risk prevention and control has established liquid casing drilling and completion fluid as a trend for the forefront development of drilling and completion fluid technology. As oil and gas exploration and development progress toward increasingly complex reservoirs, it is imperative to continue drawing inspiration from nature and further advance the theory and technology of liquid casing drilling and completion fluid to a deeper level.

4.2 Developing an Intelligent Expert System for Predicting, Evaluating, and Diagnosing Damage Mechanisms in Oil and Gas Reservoirs.

Damage mechanisms in oil and gas reservoirs exhibit specific characteristics, and significant variations are observed among different reservoirs. However, the current challenge lies in the inability to rapidly and accurately predict, evaluate, and diagnose reservoir damage in real time. This deficiency hinders the implementation of effective reservoir protection technologies. Due to the multifaceted factors that contribute to reservoir damage, a comprehensive interdisciplinary approach is necessary. This approach should integrate disciplines such as geology, chemistry, mathematics, mechanics, computer science, and petroleum engineering. Incorporating artificial intelligence techniques and employing intelligent data collection, transmission, and processing methods are essential for achieving real-time prediction, evaluation, and diagnosis. The development of intelligent expert systems will also play a crucial role in the future of intelligent or smart oil and gas fields.

Conflict of Interest

There are no conflicts of interest.

Data Availability Statement

The authors attest that all data for this study are included in the paper.

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