Plugging Efﬁciency in Fractured Carbonate Gas Reservoirs Using Fuzzy-Ball Fluids Combined with Solid Plugging Agents

: Loss encountered during workover operation is a common challenge in the development of fractured carbonate gas reservoirs. Fuzzy-ball ﬂuid, a non-solid phase plugging material developed based on Fuzzy Sealaplugging Theory, has been widely used in killing the well. However, in the plugging of fractured carbonate gas reservoirs, a substantial volume of Fuzzy-ball ﬂuid is required and the pressurization process is time-consuming, which greatly impairs its application. In this study, solid plugging agents including calcium carbonate and ﬁbers are introduced into Fuzzy-ball ﬂuids to improve the plugging efﬁciency of large-scale macro-fractures. In particular, the plugging performance was evaluated by the indoor plugging of a synthetic core containing a 5 mm wide wedge-shaped fracture, as well as by ﬁeld trials in two wells. The results show that the plugging ability of the new ﬂuid increases as the concentration of calcium carbonate or ﬁber increases. Moreover, a more signiﬁcant enhancement of plugging efﬁciency was achieved by ﬁbers. In ﬁeld applications, the use of Fuzzy-ball ﬂuids with calcium carbonate or ﬁbers reduced the volume of ﬂuid consumed by 33~74% and decreased the pressurization time by 33~69%. Therefore, by combining solid plugging agents with Fuzzy-ball ﬂuids, the dual demand for plugging efﬁciency and cost-effectiveness for fractured carbonate gas reservoirs is achieved simultaneously, which provides an alternative technique for addressing ﬂuid loss in fractured carbonate gas reservoirs.


Introduction
Carbonate reservoirs are estimated to account for approximately 70% of global hydrocarbon resources.In China, hydrocarbon resources in carbonate rocks contribute to about 27% of the country's total hydrocarbon resources, making them an important domain for hydrocarbon exploration, development, and reserve augmentation [1].The interaction of these acidic gases with tubing under high-temperature and high-pressure conditions can exacerbate corrosion, possibly leading to tubing leaks, which can impede operational implementation and pose safety risks [2].This results in challenges such as the inefficient utilization of hydrocarbon resources [3], rapid production decline, water invasion, and low recovery rates [4].
In engineering practice, the anisotropy of these reservoirs leads to various challenges, including wellbore instability and a loss of drilling fluid, and they are often referred to as fractured reservoirs [5].As gas wells begin production, the formation pressure coefficient gradually decreases, resulting in a significant pressure differential between the wellbore fluid column and the formation pressure.This necessitates temporary plugging of the production zones to create a safe wellbore environment for workover operations such as fishing, sand washing, acidizing, and fracturing [6].
Currently, workover operations for gas wells can be broadly classified into two categories: mechanical well control and fluid well control methods [7].Mechanical well control refers to the use of specialized well servicing equipment to control wellhead pressure Energies 2023, 16, 6688 2 of 13 without the need to bleed off wellbore pressure or inject working fluid [8].This method, however, lacks aspects such as seal integrity at the wellhead, mechanical temperature resistance, equipment lifespan, and corrosion resistance.Compared to mechanical well control, fluid well control offers advantages such as simpler processes, higher safety, and control costs, making it the mainstream method for workover operations [9].
The key component in fluid well control is the well control fluid.Most well-controlled fluids are either freshwater or saltwater.When injected without sealing the loss zone first, significant fluid loss can occur.Temporary plugging materials can be divided into solid and non-solid types.Solid materials are further divided into rigid and soft materials [10].Su et al. developed a rigid plugging material with a high acid solubility and serrated surface, which was compounded with lignin fiber and calcium carbonate to form a composite plugging material suitable for plugging cracks according to the principle of 1/2~2/3 bridging plugging [11].Bao et al. created a thermotropic shape-memory plugging agent based on thermo-mechanical deformation, with a pressure-bearing capacity of more than 11 MPa, which can successfully seal cracks of 2-5 mm [12].Zhang et al. experimentally evaluated the sealing ability of degradable fibers with lengths of 4-8 mm and diameters of 10-20 µm on cracks with widths of 0.5-2 mm and found that the cumulative loss was less than 60 mL in 30 min [13].However, these solid materials are difficult to remove after workover operation and are not conducive to production recovery.Zhou et al. formed a plugging agent with good alkali and salt resistance by adjusting the concentrations of the polymer, pregelator, and second crosslinker [14].Li et al. developed a high-temperature-resistant (140 • C) plugging gel with partially hydrolyzed polyacrylamide, hexamethylenetetramine, and methyl p-hydroxybenzoate, which can effectively seal cracks with widths of 2~5 mm [15].Su et al. proposed a drill-on-drill gel plugging technique, which effectively solved the loss problem caused by surface cracks [16].Zhao et al. introduced a static gel cement slurry plugging method and proved its feasibility for sealing large cavities through field trials [17].However, these soft materials require stringent subsurface reaction conditions and have limited applicability.Additionally, elastic materials, another type of soft material, present challenges in backflow [18].Well-control fluids with inherent sealing properties, such as gelled fluids, employ increased fluid viscosity to minimize fluid loss, but cannot completely prevent it; they only slow down the loss rate [19].Polymers can block the internal structure of the reservoir, causing formation damage [20].Hydrocarbonbased well control fluids can prevent equipment corrosion, water blockage, and clay swelling, but are flammable and pose a fire hazard [21].In oil and gas wells containing water, they can cause oil-water emulsification and wettability alteration [22].Foam well control fluids, composed of a gas-liquid dispersion system using an inert gas in a surfactant base fluid, have strong solid suspension capabilities and cause minimal formation damage, but their sealing ability declines over longer durations due to their short stability period [23].
The Fuzzy-ball fluid contains balls with a median diameter of 25 µm.When injected into formation channels under a loss pressure differential, these balls enter the formation channels and create a seal by accumulation [24,25], elongation, and plugging, thereby mitigating the loss pressure and improving the formation's pressure-bearing capacity [26,27].Fuzzy-ball fluid has been successfully applied for leak prevention and plugging during drilling [28], underbalanced well control in gas wells [24], diversion plugging during hydraulic fracturing [29], and water shut-off in oil wells [30].In gas well servicing, when used in conjunction with wellbore piston well-control technology, Fuzzy-ball fluid prevents the upsurge of hydrogen sulfide at the well bottom [31], and gas production recovers rapidly after breaking the gel [32].However, the application of fuzzy ball fluids is greatly hampered by the fact that they are internally sealed, require a relatively large amount of volume compared to surface sealing, and the pressurization process is time-consuming.Instead, faster and more efficient sealing is required in the field to quickly build up well-head pressure and enhance operational safety.Therefore, further enhancing the plugging efficiency of Fuzzy-ball fluids has become an urgent issue.

Study Objectives
In this study, solid-phase plugging agents including calcium carbonate and fibers were proposed to enhance the plugging ability of Fuzzy-ball fluids, considering that a combination of internal and surface seals may be beneficial.Additionally, the plugging efficiency for fractured reservoirs was evaluated by combining indoor experiments and field trials.The chapters of the paper are arranged as follows.
In Section 3, the plugging performance of the Fuzzy-ball fluids containing the different calcium carbonate or fiber contents was measured by plugging the synthetic core containing a 5 mm wide wedge-shaped fracture.The experimental materials and self-development experimental setup are introduced, and the detailed experimental procedures are given in Appendix A. In Section 4, the application process of Fuzzy-ball fluids containing fibers or calcium carbonate in two fractured carbonate gas reservoirs was presented, and the bearing capacity tests were conducted to examine the plugging effects.In Section 5, the plugging efficiency, including the fluid consumption and the time required to reach the target pressure, was analyzed by combining indoor experiments and field trials.In Section 6, the main conclusions were obtained, and in Section 7, the possible future research directions and recommendations were listed.
Through this study, a novel efficient plugging fluid was developed which provides an alternative technology for addressing the fluid loss encountered during workover operations in fractured carbonate gas reservoirs.

Experimental Materials
The Fuzzy-ball fluid used for the experiments was compounded from Fuzzy-ball coating, floss, core, and membrane agents.The solid-phase plugging materials used were calcium carbonate particles with a particle size of 80-120 mesh and plant fibers with a diameter of 10-20 µm and length of 5-6 mm.Additionally, an appropriate amount of hightemperature stabilizer was added to improve the fluid's temperature resistance, fulfilling the operational requirements of carbonate reservoirs.The specific composition and function of various materials are shown in Table 1.

Experimental Setup
Figure 2 presents the experimental instruments for evaluating the plugging efficiency of fluids.In this experiment, a 25 mm diameter tubing evaluation device was employed, considering the possibility that particle aggregation could lead to clogging of a conventional 3 mm diameter indoor pipe.Additionally, a backpressure device was added to simulate formation pressure.Note that the tubing and clamps are modular and can be disassembled to accommodate various experimental requirements.During the experiment, the air pump continuously supplies air, ensuring stable pressure and flow rates from the constant speed and pressure pump.After entering the pressure vessel, the fluid is injected at a stable rate.Notably, due to the uncertainty in the particle size of the calcium carbonate used, the clamp testing device measures 99 mm × 180 mm.The corresponding pipeline inner diameter was also enlarged to ensure a complete displacement of particles into the clamp, avoiding clogging within the pipeline.Before fluid injection, a pressure gauge is installed on the fractured core plug to simulate the wellhead injection pressure, and a hand pump provides confining pressure simulating the overlying pressure.Another hand pump is used to simulate formation pressure.At the outlet end, the volume and mass of the fluid flowing out are recorded by a measuring cylinder and high-precision balance.Notably, the plugging quantity and plugging time of fractures were monitored by measuring the quantities and pressures of the sealing materials at the inlet and outlet during different time intervals.

Experimental Setup
Figure 2 presents the experimental instruments for evaluating the plugging efficiency of fluids.In this experiment, a 25 mm diameter tubing evaluation device was employed, considering the possibility that particle aggregation could lead to clogging of a conventional 3 mm diameter indoor pipe.Additionally, a backpressure device was added to simulate formation pressure.Note that the tubing and clamps are modular and can be disassembled to accommodate various experimental requirements.During the experiment, the air pump continuously supplies air, ensuring stable pressure and flow rates from the constant speed and pressure pump.After entering the pressure vessel, the fluid is injected at a stable rate.Notably, due to the uncertainty in the particle size of the calcium carbonate used, the clamp testing device measures 99 mm × 180 mm.The corresponding pipeline inner diameter was also enlarged to ensure a complete displacement of particles into the clamp, avoiding clogging within the pipeline.Before fluid injection, a pressure gauge is installed on the fractured core plug to simulate the wellhead injection pressure, and a hand pump provides confining pressure simulating the overlying pressure.Another hand pump is used to simulate formation pressure.At the outlet end, the volume and mass of the fluid flowing out are recorded by a measuring cylinder and high-precision balance.Notably, the plugging quantity and plugging time of fractures were monitored by measuring the quantities and pressures of the sealing materials at the inlet and outlet during different time intervals.Synthetic cores with a diameter of 99 mm and length of 180 mm were used, containing 30 mm × 5 mm through-going fractures to simulate large-scale loss channels in the formation.Notably, the maximum width of the fracture in carbonate reservoirs is about 5 mm through a large number of core analyses.The confining pressure was set at 25 MPa Synthetic cores with a diameter of 99 mm and length of 180 mm were used, containing 30 mm × 5 mm through-going fractures to simulate large-scale loss channels in the formation.Notably, the maximum width of the fracture in carbonate reservoirs is about 5 mm through a large number of core analyses.The confining pressure was set at 25 MPa and a backpressure of 0.5 MPa was applied at the outlet of the indoor core; injection was performed continuously at rates ranging from 0.1 to 5.0 mL/min.
The specific experimental procedures are given in Appendix A. Only the main processes are given here.The constant-speed, constant-pressure pump was initiated and the stopwatch was started concurrently.During the experiment, the inlet pressure and outlet flow rate were recorded every 5 min.Initially, the outlet flow rate was 0 and the inlet pressure rose slowly.When fluid began to flow from the backpressure valve connected to the outlet, the inlet pressure had already exceeded the backpressure setting (0.5 MPa), and the flow rate was relatively fast initially.As time progressed, the outlet flow rate decreased and the inlet pressure increased more rapidly.The experiment concluded once the inlet pressure reached 20 MPa, at which point the time taken to reach this pressure and the outlet flow rate were recorded.The used core before and after the experiment is shown in Figure 3.As can be seen, the fracture in the core was successfully sealed after the experiment.Synthetic cores with a diameter of 99 mm and length of 180 mm were used, containing 30 mm × 5 mm through-going fractures to simulate large-scale loss channels in the formation.Notably, the maximum width of the fracture in carbonate reservoirs is about 5 mm through a large number of core analyses.The confining pressure was set at 25 MPa and a backpressure of 0.5 MPa was applied at the outlet of the indoor core; injection was performed continuously at rates ranging from 0.1 to 5.0 mL/min.
The specific experimental procedures are given in Appendix A. Only the main processes are given here.The constant-speed, constant-pressure pump was initiated and the stopwatch was started concurrently.During the experiment, the inlet pressure and outlet flow rate were recorded every 5 min.Initially, the outlet flow rate was 0 and the inlet pressure rose slowly.When fluid began to flow from the backpressure valve connected to the outlet, the inlet pressure had already exceeded the backpressure setting (0.5 MPa), and the flow rate was relatively fast initially.As time progressed, the outlet flow rate decreased and the inlet pressure increased more rapidly.The experiment concluded once the inlet pressure reached 20 MPa, at which point the time taken to reach this pressure and the outlet flow rate were recorded.The used core before and after the experiment is shown in Figure 3.As can be seen, the fracture in the core was successfully sealed after the experiment.

Field Application
In Field S, a Fuzzy-ball fluid containing fibers was employed due to severe fluid loss; while in Field P, where fluid loss was relatively small, a Fuzzy-ball fluid-containing calcium carbonate was chosen.

Field Application in Well S-3X
Well S-3X is in the Yishan Slope structural zone of the Ordos Basin in China, and the schematic diagram of its wellbore structure and string is shown in Figure 4.The primary production layer is Mawu, a carbonate rock gas layer with a vertical depth of 3450.8-3505.9m and is characterized by the presence of natural fractures and solution cavities.During drilling, upon penetration into the reservoir, the well experienced a cumulative fluid loss exceeding 2000 m 3 .After the well completion and subsequent acidizing treatment, the gas flow rate tested without restrictions exceeded 200 × 10 4 m 3 /d.By now, well S-3X has been in production for nearly 20 years, with the formation pressure coefficient decreasing to 0.40.Through this workover operation, the original tubing was lifted out and lowered into sulfur-resistant tubing to restore production.The workover process is as follows: kill the well, lift out the string, clear the well, lower the completion string, gas lift, fluid discharge, and well completion.During the first well-kill operation, 500 m 3 of Fuzzy-ball fluid for workover was injected over 13 h, with the surface pumping pressure increasing to 3 MPa.The anticipated plugging effect was not achieved.However, during the second well-kill operation, 130 m 3 of Fuzzy-ball fluid for workover with the addition of 0.5% fibers was injected, and the pumping pressure increased to 7.9 MPa within 4 h.This indicates that the addition of fibers significantly increased the plugging capacity of the Fuzzy-ball fluid.

Field Application in Well P2-Y
Well P2-Y is a gas well located in the Sichuan Basin, China, and the schematic diagram of its wellbore structure and completion string is shown in Figure 5.As can be seen, well P2-Y is a directional well with a depth of 6095.31m, and the target production layer is T1f1-2 with a depth of 5827.9-6004.3 m.Following hydraulic fracturing and acidizing, the unimpeded flow rate tested was 350 × 10 4 m 3 /d.After more than 20 years of production, the formation pressure coefficient dropped to 0.35.For well P2-Y, there is severe casing deformation.To restore the production, it is necessary to carry out pulling string workover operations.The squeeze injection method was used for well-killing, and the wellhead pressure was adjusted or the fluid was replenished according to the change in tubing pressure.
The adjacent well, D5-Z, was successfully sealed within 3 h after the injection of 120 m 3 of Fuzzy-ball fluid.Due to the presence of hydrogen sulfide gas in well P2-Y, it was desirable to shorten the plugging time.On-site, 80 m 3 of Fuzzy-ball fluid containing 100 mesh calcium carbonate particles was prepared.After two hours of injection, the surface pumping pressure increased by 5 MPa, indicating successful plugging.

Fluid Consumption to Reach the Target Pressure
In the field, wells S-3X and P2-Y demonstrated enhanced formation pressure-bearing capabilities after operating with Fuzzy-ball fluid containing solid plugging agents, achieving 34 and 39 MPa, respectively, when normalized to the well depth.For comparison, the volume of fluid injected was recorded indoors at different concentrations of calcium carbonate and fibers upon reaching an injection pressure of 20 MPa, as shown in Figure 6.It can be observed that the consumed fluid volume decreased approximately linearly with increasing calcium carbonate or fiber concentration.Specifically, the consumed fluid volume decreased from 1832 to 975 mL as the concentration of calcium carbonate increased from 0.1% to 1.5%, whereas adding only 0.1% fibers reduced the volume of fluid consumed to 424 mL, and as the fiber concentration increased to 1.5%, the volume of fluid consumed decreased to 218 mL.Therefore, fibers exhibit a higher plugging efficiency than calcium carbonate under the same conditions.In the field applications, the surface pumping pressures we tested after successfully killing the wells.An increase in surface pumping pressure represents, firstly, the success of the plugging operation.Secondly, it was considered that subsequent fluid circulation causes surge pressures, which could lead to losses.Thus, a bearing pressure test is needed.Here, bearing pressures of 7.9 and 5 MPa for well S-3X and well P2-Y were sufficient to ensure that no loss occurred even with fluid circulation.
Field data indicate that in well S-3X, the volume of fluid consumed was reduced by 74% with the addition of fibers compared to the initial well-killing operation, while in well P2-Y, the volume of fluid consumed was reduced by 33% with the addition of calcium carbonate as compared to an adjacent well.These observations are consistent with the results obtained from laboratory experiments.

Time Required to Reach the Target Pressure
Figure 7 shows the time required to reach 20 MPa with varying concentrations of calcium carbonate and fibers.As can be seen at the same concentration, the time required for Fuzzy-ball containing fiber is lower than that for Fuzzy-ball containing fiber calcium carbonate.Furthermore, the time required decreased approximately linearly with increasing calcium carbonate or fiber concentration.Specifically, the time decreased from 267 and 234 to 152 and 98 min as the concentration of calcium carbonate and fiber increased from 0.1% to 1.5%, respectively.In the field applications, the surface pumping pressures we tested after successfully killing the wells.An increase in surface pumping pressure represents, firstly, the success of the plugging operation.Secondly, it was considered that subsequent fluid circulation causes surge pressures, which could lead to losses.Thus, a bearing pressure test is needed.Here, bearing pressures of 7.9 and 5 MPa for well S-3X and well P2-Y were sufficient to ensure that no loss occurred even with fluid circulation.
Field data indicate that in well S-3X, the volume of fluid consumed was reduced by 74% with the addition of fibers compared to the initial well-killing operation, while in well P2-Y, the volume of fluid consumed was reduced by 33% with the addition of calcium carbonate as compared to an adjacent well.These observations are consistent with the results obtained from laboratory experiments.

Time Required to Reach the Target Pressure
Figure 7 shows the time required to reach 20 MPa with varying concentrations of calcium carbonate and fibers.As can be seen at the same concentration, the time required for Fuzzy-ball containing fiber is lower than that for Fuzzy-ball containing fiber calcium carbonate.Furthermore, the time required decreased approximately linearly with increasing calcium carbonate or fiber concentration.Specifically, the time decreased from 267 and 234 to 152 and 98 min as the concentration of calcium carbonate and fiber increased from 0.1% to 1.5%, respectively.In the field applications, the surface pumping pressures we tested after successfully killing the wells.An increase in surface pumping pressure represents, firstly, the success of the plugging operation.Secondly, it was considered that subsequent fluid circulation causes surge pressures, which could lead to losses.Thus, a bearing pressure test is needed.Here, bearing pressures of 7.9 and 5 MPa for well S-3X and well P2-Y were sufficient to ensure that no loss occurred even with fluid circulation.
Field data indicate that in well S-3X, the volume of fluid consumed was reduced by 74% with the addition of fibers compared to the initial well-killing operation, while in well P2-Y, the volume of fluid consumed was reduced by 33% with the addition of calcium carbonate as compared to an adjacent well.These observations are consistent with the results obtained from laboratory experiments.

Time Required to Reach the Target Pressure
Figure 7 shows the time required to reach 20 MPa with varying concentrations of calcium carbonate and fibers.As can be seen at the same concentration, the time required for Fuzzy-ball containing fiber is lower than that for Fuzzy-ball containing fiber calcium carbonate.Furthermore, the time required decreased approximately linearly with increasing calcium carbonate or fiber concentration.Specifically, the time decreased from 267 and 234 to 152 and 98 min as the concentration of calcium carbonate and fiber increased from 0.1% to 1.5%, respectively.Field trials indicate that in well S-3X, the time required was reduced by 69% with the addition of fibers, compared to the initial well-killing operation, while in well P2-Y, the time required was reduced by 33% with the addition of calcium carbonate as compared to an adjacent well.Consequently, the field application effect is consistent with the indoor-tested results.
In addition, the choice between calcium carbonate and fibers depends on several factors, such as the need for subsequent reservoir recovery or acid fracturing treatments.Calcium carbonate is soluble in acid, allowing for faster recovery in scenarios requiring acidization.Fibers, possessing biodegradable properties, provide an extended plugging duration but require a longer period to equalize formation pressure.

Plugging Mechanism of Fuzzy-Ball Fluid Containing Solid Plugging Agents
The status of water, solid-free Fuzzy-ball fluid, and Fuzzy-ball fluid containing solid plugging agents during the plugging of subsurface leak pathways are illustrated in Figure 8.As observed, using water for well killing leaves no material to obstruct the flow within fractures.Thus, water flows through the formation of fissures, leading to fluid losses (Figure 8a).In contrast, Fuzzy-ball fluid accumulates in the formation fractures, forming a barrier layer that effectively reduces losses (Figure 8b).This contributes to Fuzzy-ball plugging the formation leak pathways of various sizes following the Fuzzy Sealaplugging Law, without reliance on chemical reactions to form solid or near-solid structures.They adjust the plugging state according to the environmental temperature and pressure and possess intelligent fluid characteristics.However, using Fuzzy-ball fluid requires larger volumes and a longer plugging time.The introduction of solid plugging agents, such as calcium carbonate and fibers, increases the fluid's flow resistance, thus reducing the volume of fluid needed and the plugging time, as depicted in Figure 8c.
Field trials indicate that in well S-3X, the time required was reduced by 69% with the addition of fibers, compared to the initial well-killing operation, while in well P2-Y, the time required was reduced by 33% with the addition of calcium carbonate as compared to an adjacent well.Consequently, the field application effect is consistent with the indoortested results.
In addition, the choice between calcium carbonate and fibers depends on several factors, such as the need for subsequent reservoir recovery or acid fracturing treatments.Calcium carbonate is soluble in acid, allowing for faster recovery in scenarios requiring acidization.Fibers, possessing biodegradable properties, provide an extended plugging duration but require a longer period to equalize formation pressure.

Plugging Mechanism of Fuzzy-Ball Fluid Containing Solid Plugging Agents
The status of water, solid-free Fuzzy-ball fluid, and Fuzzy-ball fluid containing solid plugging agents during the plugging of subsurface leak pathways are illustrated in Figure 8.As observed, using water for well killing leaves no material to obstruct the flow within fractures.Thus, water flows through the formation of fissures, leading to fluid losses (Figure 8a).In contrast, Fuzzy-ball fluid accumulates in the formation fractures, forming a barrier layer that effectively reduces losses (Figure 8b).This contributes to Fuzzy-ball plugging the formation leak pathways of various sizes following the Fuzzy Sealaplugging Law, without reliance on chemical reactions to form solid or near-solid structures.They adjust the plugging state according to the environmental temperature and pressure and possess intelligent fluid characteristics.However, using Fuzzy-ball fluid requires larger volumes and a longer plugging time.The introduction of solid plugging agents, such as calcium carbonate and fibers, increases the fluid's flow resistance, thus reducing the volume of fluid needed and the plugging time, as depicted in Figure 8c.In summary, the use of Fuzzy-ball fluids containing calcium carbonate or fibers reduced the volume of fluid consumed by 33~74% and decreased the pressurization time by 33~69%.Therefore, the addition of solid plugging agents to the Fuzzy-ball fluid can significantly improve the plugging efficiency and reduce the operation cost, especially in scenarios with large leak pathways such as macro-fractures and karst caves in carbonate gas reservoirs that require rapid and effective plugging.However, how to quantitatively select solid plugging agents, as well as optimize the performance of the fluid based on formation conditions and project requirements, needs to be further studied.

Conclusions
In this study, the integration of Fuzzy-ball fluid with solid plugging agents such as calcium carbonate and fibers is proposed to improve the plugging efficiency of large-scale macroscopic cracks, and the plugging performance of the new fluid is measured by both indoor experiments and field tests.The following conclusions can be drawn.
1.The plugging efficiency of the new fluid increases as the concentration of calcium carbonate or fiber increases, and a more significant enhancement of plugging efficiency was achieved by fibers.Additionally, both the fluid consumed and the time In summary, the use of Fuzzy-ball fluids containing calcium carbonate or fibers reduced the volume of fluid consumed by 33~74% and decreased the pressurization time by 33~69%.Therefore, the addition of solid plugging agents to the Fuzzy-ball fluid can significantly improve the plugging efficiency and reduce the operation cost, especially in scenarios with large leak pathways such as macro-fractures and karst caves in carbonate gas reservoirs that require rapid and effective plugging.However, how to quantitatively select solid plugging agents, as well as optimize the performance of the fluid based on formation conditions and project requirements, needs to be further studied.

Conclusions
In this study, the integration of Fuzzy-ball fluid with solid plugging agents such as calcium carbonate and fibers is proposed to improve the plugging efficiency of large-scale macroscopic cracks, and the plugging performance of the new fluid is measured by both indoor experiments and field tests.The following conclusions can be drawn.

1.
The plugging efficiency of the new fluid increases as the concentration of calcium carbonate or fiber increases, and a more significant enhancement of plugging efficiency was achieved by fibers.Additionally, both the fluid consumed and the time required to reach the pre-determined bearing pressure decreased approximately linearly with increasing calcium carbonate or fiber concentration.

2.
The combination of Fuzzy-ball fluids with solid plugging agents could address the loss encountered during workover operation in fractured carbonate gas reservoirs and greatly improve plugging efficiency.Field trials indicate the use of Fuzzy-ball fluids with calcium carbonate or fibers reduced the fluid consumed by 33~74% and decreased the pressurization time by 33~69%.The surface pumping pressure reaches 5 and 7.9 MPa, ensuring no loss even after fluid circulation.

3.
The integration of solid plugging agents with Fuzzy-ball fluid could improve the plugging efficiency, reduce the consumption of Fuzzy-ball fluid, and address the associated challenges of slow pressurization and high consumption.Therefore, Fuzzyball fluid combined with solid plugging agents provides an optional technology for the plugging of fractured carbonate reservoirs.

Future Work
These findings indicate the innovation and contributions of this study to the field of fractured reservoir plugging.However, to advance the technology and guide its application in the field, the following work needs to be carried out in the future.

1.
The quantitative relationships between pressurization speed, fluid consumption, and fluid performance have not yet been determined, and no consistent trends have been established, which leads to a certain blindness in field application.Consequently, more tests should be conducted to find this quantitative relationship.

2.
Only two solid-phase plugging agents, calcium carbonate and fiber, were investigated in this study, and the feasibility of integrating with other materials, such as resins and cement, with Fuzzy-ball fluids is not yet known.This is another research direction.

3.
To understand the mechanisms of Fuzzy-ball fluids containing various solid-phase plugging materials, the corresponding mechanical modeling and numerical simulations need to be carried out in the following work.

Figure 1 showsFigure 1 .
Figure1shows Fuzzy-ball fluids and fluid with added fibers or calcium carbonate.As can be seen, fibers and calcium carbonate are suspended in the fluid and evenly dispersed, which proves that the new working fluids have stable performances and fulfill the on-site pumping requirements.

14 Figure 2 .
Figure 2. Schematic illustration of fractured core creation at different scales.

Figure 2 .
Figure 2. Schematic illustration of fractured core creation at different scales.

( 1 )
Measurement of the volume of sealing fluid used to reach the target pressure.With a set injection rate of 5 mL/min and mass concentrations of 0.1%, 0.2%, 0.5%, 1.0%, and 1.5% of calcium carbonate particles in the flocculated fluid, the cumulative injection volumes recorded at the fracture inlet when the driving pressure reached 20 MPa were 1832 mL, 1547 mL, 1324 mL, 1085 mL, and 975 mL, respectively.Similarly, with the same flow rate and mass concentrations of 0.1%, 0.2%, 0.5%, 1.0%, and 1.5% of the fiber in flocculated fluid, the cumulative injection volumes were 424 mL, 389 mL, 342 mL, 290 mL, and 218 mL, respectively.Notably, the choice of 20 MPa was determined based on the reservoir conditions.The vertical depth of the well is around 3500 m, i.e., the fluid pressure at the bottom of the well is about 35 MPa.With production, the formation pressure decays to about 15 MPa.Therefore, the difference between the two is 20 MPa, i.e., the pressure-bearing capacity of the plugging zone should be 20 MPa.(2) Measurement of the time taken to reach the target pressure.With an injection rate of 5 mL/min and mass concentrations of 0.1%, 0.2%, 0.5%, 1.0%, and 1.5% of calcium carbonate particles in the Fuzzy-ball fluid, the times recorded to reach a driving pressure of 20 MPa at the fracture inlet were 267 min, 238 min, 205 min, 179 min, and 152 min, respectively.Similarly, with the same flow rate and mass concentrations of 0.1%, 0.2%, 0.5%, 1.0%, and 1.5% of the fiber in the Fuzzy-ball fluid, the times recorded were 234 min, 209 min, 157 min, 124 min, and 98 min, respectively.

Figure 2 .
Figure 2. Schematic illustration of fractured core creation at different scales.

Figure 3 .
Figure 3.The initial core (a), and cores after sealing by fuzzy ball fluid containing fibers (b) or calcium carbonate (c).

Figure 3 .
Figure 3.The initial core (a), and cores after sealing by fuzzy ball fluid containing fibers (b) or calcium carbonate (c).

Figure 4 .
Figure 4. Schematic diagram of wellbore structure and string of well S-3X.

Figure 5 .
Figure 5. Schematic diagram of wellbore structure (a) and string (b) of well P2-Y.

Figure 6 .
Figure 6.Fluid consumed to reach 20 MPa with varying concentrations of calcium carbonate and fibers.

Figure 7 .
Figure 7. Time required to reach 20 MPa with varying concentrations of calcium carbonate and fibers.

Figure 6 .
Figure 6.Fluid consumed to reach 20 MPa with varying concentrations of calcium carbonate and fibers.

Figure 6 .
Figure 6.Fluid consumed to reach 20 MPa with varying concentrations of calcium carbonate and fibers.

Figure 7 .
Figure 7. Time required to reach 20 MPa with varying concentrations of calcium carbonate and fibers.

Figure 7 .
Figure 7. Time required to reach 20 MPa with varying concentrations of calcium carbonate and fibers.

Figure 8 .
Figure 8. Schematic representation of plugging using water (a), solid-free Fuzzy-ball fluid (b), and Fuzzy-ball fluid containing solid plugging agents (c).

Figure 8 .
Figure 8. Schematic representation of plugging using water (a), solid-free Fuzzy-ball fluid (b), and Fuzzy-ball fluid containing solid plugging agents (c).

Table 1 .
Specific components and function of experimental materials.