Damage Mechanism of Deep Coalbed Methane Reservoir and Novel Anti-Waterblocking Protection Technology

Abstract

Coalbed Methane (CBM) accounts for about 5% of China’s domestic gas supply, which has been regarded as one of the most promising energies for alleviating the energy supply–demand imbalance. Deep CBM reservoirs have the characteristics of low permeability, low porosity, and low water saturation, which easily experience reservoir damage during the drilling process, further affecting the gas productivity. Based on the analysis of coal mineral composition, pore structure distribution, and the surface micromorphology change in coal surface before and after hydration, a possible mechanism for CBM formation damage was revealed. It was found that the damage caused by drilling fluid intrusion can be divided into three stages: stripping, migration, and plugging. Based on the water-sensitive, acid-sensitive, and stress-sensitive evaluation tests, a novel anti-waterblocking agent with both wettability alteration and surface tension reduction was developed; then a reservoir protection drilling fluid for deep coal formation in Daning-Jixian block was constructed; then the reservoir protection performance of drilling fluid was evaluated. The results show that as the concentration of the anti-waterblocking agent FSS increases from 0% to 1%, the surface tension of the water phase is significantly reduced from 72.15 mN/m to 26.58 mN/m, while the maximum contact angle of water on the surface reaches 117°. This enhancement in wettability leads to an improvement in the permeability recovery rate from 56.6% to 80.0%, indicating a substantial reduction in waterblocking effects and better fluid mobility within the reservoir. These findings highlight the efficacy of FSS in mitigating formation damage and optimizing gas production in coalbed methane reservoirs. The drilling fluid has good wettability alteration, inhibition, and sealing performance, which is of great significance for protecting gas well productivity.

1. Introduction

Coalbed Methane (CBM) is natural gas found in coal deposits; the proven reserves and production have grown nearly every year since the end of the 20th century. Coalbed methane has become a crucial growth point for increasing oil and gas reserves in China [1,2]. The exploration and development of CBM in China and the US has accelerated annually, leading to a significant rise in drilling operations. CBM production accounts for about 5% of China’s domestic gas supply and an annual increase of 18% in 2023 [3]. Currently, the exploration and development of coalbed methane in China primarily focus on shallow and mid-depth coal seams (<1500 m). However, the reserves of the deep coalbed methane resources with depths of 1500–3000 m reach 30.4 trillion cubic meters, indicating tremendous development potential for deep CBM [4,5,6]. At present, large-scale production in the Qinshui and the Ordos Basin has been achieved; the efficient development of this block is of great significance for alleviating the energy supply–demand imbalance.

The primary sources of coalbed methane include adsorbed gas on the coal matrix surface, free gas in fractures, dissolved gas in coal seam water, and free gas in thin sandstone and carbonate rock reservoirs within coal seams. Compared to conventional sandstone and carbonate rock reservoirs, coalbed methane reservoirs exhibit high adsorption capacity and low permeability and are susceptible to compression and fragmentation. These characteristics determined that coal seams would suffer more damage than conventional reservoirs during the drilling operation, further affecting the desorption, diffusion, migration, and subsequent production of coalbed methane. Zheng et al. [7] investigated a fuzzy ball drilling fluid, which can overcome the dilemma where collapse and loss take place in the same coalbed methane well by reforming the formation in the near-wellbore region; meanwhile, the microstructure of fuzzy balls can also improve the rock mechanics parameters. Lyu et al. [8] prepared a degradable polymer drilling fluid system with low density and filtration loss, which is conducive to flowback and reduces the damage to the coal reservoirs. Generally, drilling fluid interacts with coal rocks directly during the drilling process. Cai et al. [9] used a clay-free micro-foamed drilling fluid stabilized by nano-silica particles to avoid formation damage. Coal with a low mechanical strength often experiences structural collapse, further leading to formation damage. Therefore, one of the key roles of drilling fluid is to maintain the borehole stability.

Wettability is one of the most important surface properties of rock. It controls the magnitude and direction of capillary force and affects fines migration. Generally, water will imbibe into porous media to form a liquid-blocking region due to the capillary force, which can kill the gas production. Additionally, there are certain amounts of clay minerals in coal formation, such as montmorillonite and illite–smectite mixed layer; these minerals would expand and disperse by contacting with water, resulting in the wellbore instability. Chen et al. [10] studied high-inhibitive and low-damage drilling fluids, which can maintain wellbore stability by electrical inhibition and neutral wetting.

In this paper, the reservoir properties of the deep coal rock from the Daning-Jixian block was analyzed by means of XRD, SEM, and BET methods; a potential mechanism for reservoir damage was firstly revealed. Based on this reservoir damage mechanism, high-performance waterblocking prevention agents were prepared; the capacity of wettability alternation and decreasing surface tension were investigated by the contact angle measurement and surface tension meter. By utilizing wetting reversal and surface tension reduction strategies, a reservoir protection drilling fluid system suitable for the coal-bearing formations of the Daning-Jixian block was developed; then the reservoir protection performance of drilling fluid was evaluated, exhibiting an excellent capacity of wettability alternation, low Surface Tension, and permeability recovery.

2. Experimental Section

2.1. Materials

Anti-waterblocking agent, prepared in the laboratory; cationic inhibitor, prepared in the laboratory; and ethanol, AR were purchased from Shanghai Macklin Biochemical Technology Co., Ltd., Shanghai, China; rock samples were provided by the Daning-Jixian block, diameter 2.5 cm, length 5–7 cm.

2.2. Surface Structure Evaluation

The morphology and surface structure of samples were explored via a high-power microscope and the SEM (Zeiss Merlin Compact, Germany) technique, procedures as follows: polishing the core samples to a smooth, horizontal surface using 800-grit metallographic sandpaper; placing the fully polished rock samples in deionized water and aging for 16 h. After aging, samples were dried at a temperature of 80 °C; then the samples’ surface was sprayed with a thin layer of gold to enhance the electroconductibility, and the morphology changes in rock samples before and after hydration were analyzed, and we characterized the surface morphology of the coal samples from the field with SEM (Gemini 450, Zeiss, Jena, Germany). The crystal information of rock samples was analyzed by the XRD technique.

2.3. Characterization

(1)

Contact Angle Measurement

Coal samples were cut into slices with a diameter of 2.5 cm and a thickness of 0.5 cm using a core cutter, and polished with 800-grit metallographic sandpaper to ensure a flat and consistent surface. The rock samples were then immersed in solutions with different concentrations of anti-waterblocking agent for 24 h to simulate wettability changes under various treatment conditions [11]. The samples were dried at 80 °C to remove any residual moisture and ensure accurate measurements. The contact angle of distilled water on the treated core surfaces was measured using the OCA-25 optical contact angle meter to evaluate the improvement in surface wettability induced by the anti-waterblocking agent.

(2)

Spontaneous Imbibition Experiment

To study the effect of the anti-waterblocking agent on the spontaneous imbibition behavior of coal samples, a core spontaneous imbibition apparatus was used. First, a certain amount of anti-waterblocking agent was added to formation water and stirred evenly using a magnetic stirrer to ensure uniform distribution. The polished core was suspended vertically below a precision balance, and a beaker containing the test solution was placed on a lift platform directly beneath the core. The lift platform was adjusted so that the surface of the solution in the beaker just touched the bottom end face of the core. The balance recorded the weight change of the rock over time in real time to observe the imbibition behavior and rate, analyzing the effectiveness of the anti-waterblocking agent.

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Permeability Recovery Experiment

A core flow apparatus was used to measure the initial gas permeability (Kg1) of two dry cores to establish baseline permeability. The cores were then saturated with formation water and anti-waterblocking solution, respectively, to simulate formation conditions post-drilling fluid invasion. Nitrogen gas was used to displace the cores until no more water was produced, ensuring that residual liquid would not affect subsequent measurements. The gas permeability after displacement (Kg2) and residual water saturation of the cores were then measured, and the permeability recovery rate (Kg2/Kg1) was calculated. By comparing the permeability recovery rates under different treatments, the effectiveness of the anti-waterblocking agent in mitigating water blocking and improving core permeability could be evaluated.

3. Results and Discussion

3.1. Clay Mineral and Surface Structure Analysis of Coal Samples

(1)

Reservoir Rock Clay Mineral Analysis

The samples from Daning block primarily consist of bright coal and vitrain, with the coal structure predominantly being primary structure coal. The organic matter content in the coal samples ranges from 90.2% to 96.5%; the average content reaches 93.8%. The contents of clay mineral range from 0.6% to 2.2%; the hydration expansibility of the coal is weak. The content of sulfide minerals ranges from 0.2% to 0.8%. The content of carbonate minerals ranges from 0.5% to 4.7%, with an average content of 1.5%. The content of silica ranges from 0.9% to 7.3%, then coal is brittle, as shown in

Table 1. Results of microcomponents determination for coal rocks.

No	Organic Matter/%	Clay/%	Sulfide/%	Carbonate/%	Silica/%
Daning-1-1	95.9	0.6	0.8	0.8	1.9
Daning-1-2	90.9	1.1	0.7	4.7	2.6
Daning-1-3	90.2	1.1	0.5	0.9	7.3
Daning-1-4	95.4	2.2	0.4	0.5	1.5
Daning-1-5	96.5	1.8	0.2	0.6	0.9

.

(2)

X-ray diffraction analysis of coal rock

X-ray diffraction was used to study the crystal structure of rock samples, as shown in Figure 1. The coal rock samples from the Daning block mainly contain quartz (25.9°), plagioclase (28.5°), calcite (28.8°), and dolomite (32.6°). The characteristic peak of quartz shows the largest peak area, indicating the content of quartz in the surface rock samples is the highest. The relative brittleness of the rock sample means that it is more prone to brittle fracturing under stress or even under minimal external forces, making it more likely to undergo brittle deformation during drilling, forming debris. This debris accumulates in fractures, pore throats, and other locations, thereby blocking gas flow channels and restricting gas movement [12,13].

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Surface morphology of coal rock

The surface morphology of coal rock in the Daning block was studied using a high-power metallographic microscope. It was found that the coal blocks exhibit endogenetic cleats, face cleats, “feather-like” microfractures (Figure 2a,b), and “bulbous” pore throats. The scales of these fractures range from 1 to 15 μm. Additionally, there are irregular cavernous pore throats within the rock core (Figure 2c,d), with the narrowest connection between pore throats being only 5 μm. Therefore, mineral particles with micron size would be carried by fluid, which can easily block these small pore throats, causing the fractures within the reservoir to form into narrow–long fractures. And the narrow–long fractures, due to their geometric shape and narrow dimensions, exhibit significant capillary forces. When fluid enters these fractures, the capillary forces draw the liquid into the fractures through imbibition, leading to localized liquid blockage, which leads to cumulative reservoir damage and affects gas well productivity. And the narrow–long fractures with strong capillary force can cause local liquid-blocking effects through imbibition, leading to cumulative reservoir damage and affecting gas well productivity [14].

(4)

Specific surface area and pore-size analysis of coal rock

Table 2. Specific surface area and pore-size analysis of coal rock.

No	Lithology	Specific Surface Area (m2/g)	Average Pore Size (nm)
Daning 1	Coal	0.0195	8.3429
Daning 2	Coal	0.282	19.382
Daning 3	Coal	0.277	14.207
Daning 4	Coal	0.155	8.949
Daji 1	Shale	3.8780	4.4130
Daji 2	Shale	1.0480	9.2710
Daji 3	Shale	4.1630	4.3330

shows the specific surface area and pore-size analysis of the coal rock in the Daning block. The reservoir mainly consists of coal rock and shale. The specific surface area of the coal rock in the Daning block is relatively low, with a maximum of 0.282 m²/g, and the average pore size is 12.7 nm. The specific surface area of shale in the Daning block is higher than that of coal rock, with an average pore size of about 5.96 nm. Generally, water imbibition is easily caused by the capillary [15].

3.2. CBM Reservoir Damage Mechanisms

(1)

Surface morphology change before and after hydration

The surface morphologies of coal rock before and after hydration were analyzed using scanning electron microscopy (SEM). Generally, the original morphology of coal surface exhibited abundant pores with a high surface roughness and microfractures (Figure 3a). The microfractures between mineral crystals is filled by a small amount of clay and sand, and the irregular particles attached to the surface. After 16 h of immersion in water, the number of irregular particles on the coal block surface decreased, and the amount of small pores reduced; the sizes of pores shrank from 300 nm to 150 nm after hydration, as shown in Figure 3f. This phenomenon is caused by the hydration expansion of clay minerals within coal pores, which further reduces the hydrated pore diameter and narrows the original gas flow channels, leading to changes in the pore structure. Additionally, some clay mineral particles may fracture and detach from the rock surface after hydration expansion. These fine particles tend to accumulate in the narrowed pore throats, forming localized blockages. The reduced pore diameter also increases capillary pressure, further exacerbating liquid retention within the pores and intensifying blockages in the gas flow channels, resulting in cumulative reservoir damage [16,17].

Reservoir damage in the Daning block caused by the invasion of the drilling fluid occurs in three stages: particle detached from the rock surface, particle transportation, and particles deposit and block pores. This is mainly due to the weak interaction between tiny mineral particles with the rock surface, making it easy for these particles to detach from the pore walls under the interaction of high-speed gas flow [18]. Subsequently, the transported particles will block the pores under the influence of fluid movement, causing reservoir damage, as shown in Figure 4.

(2)

Swelling study of coal rock

Coal rock was ground to powder using a grinder with 300 mesh, and the powder sample was separately added to formation water and deionized water to investigate the swelling properties of coal rock and shale, as shown in Figure 5. The swelling of coal rock from the Daning block in the formation water was minimal, while in deionized water, the swelling height of coal increased to 5 mm, indicating a certain degree of swelling. The swelling height of shale increased to 5.5 mm and 6 mm after soaking for 24 h in the formation water and deionized water, respectively. This is due to the hydration and swelling of clay minerals in the shale, increasing the interlayer spacing of the crystal layers [19,20].

(3)

Sensitivity Analysis of Daning blocking

Water Sensitivity Evaluation: KCl solutions, KCl solutions with half the salinity of formation water, and distilled water were used as the experimental fluids to displace the rock core. The permeability under different fluids displacement was calculated. The experimental results showed that the water sensitivity of coal rock is strongly water-sensitive, as shown in

Table 3. Results of water sensitivity analysis of coal rock.

Sample	K0/(10−3μm2)	KCl/(mg/L)	K1/(10−3μm2)	Damage Extent/%
Daning 1	0.0045	150,000	0.0024	46.6
		75,000	0.0013	71.1
		0	0.0014	68.9

.

Acid Sensitivity Evaluation: Acid sensitivity refers to the phenomenon where acid entering the reservoir reacts with acid-sensitive minerals and reservoir fluids, producing precipitates or releasing particles, thereby changing the permeability of the reservoir. The pH value of formation water in the Daning block ranges from 4 to 6, exhibiting slight acidity. As shown in

Table 4. Results of acid sensitivity analysis of coal rock.

Sample	K0/(10−3μm2)	pH	K1/(10−3μm2)	Damage Extent/%
Daning 5	0.0032	4	0.0019	40.6
Daning 6	0.0035	6	0.0026	25.7
Daning 7	0.0019	7	0.0014	26.3

, the damage degree of acid sensitivity ranges from 25.7% to 40.6%, indicating moderate to weak acid sensitivity.

After the injection of solid particles with the same concentration with different particle size, the permeability of coal cores showed different degrees of decrease, as shown in

Table 5. Results of acid sensitivity analysis of coal rock.

Sample	K0/(10−3μm2)	K1/(10−3μm2)	Damage Extent/%
Daning 8	0.0047	0.0029	38.3
Daning 9	0.0052	0.0024	53.8
Daning 10	0.0104	0.0058	44.2

. The permeability of coal sample Daning-8 with particle A has the lowest damage extent (38.3%), followed by that of coal sample Daning-10. The largest damage extent was caused by particle B in the Daning-9 sample, and the damage extent is as high as 53.8%.

Figure 6 shows the influence of HCl solution on the gas permeability of coal rock. The coal rock sample was treated in 10% HCl solution for 1 h; then the gas permeability of the sample increased by 8 to 12 times, indicating a significant improvement in reservoir permeability. According to the rock mineral analysis results, a large amount of calcite and other acid-reactive minerals filled the fractures in the coal rock. When immersed in the acid condition, calcite reacted with the acid, connecting the coal rock pores and fractures, significantly increasing permeability. However, some insoluble materials with micron size could block the pores during the displacement process.

Stress Sensitivity: Reservoir pressure changes with the continuous extraction of reservoir fluids, causing the effective stress change on reservoir rocks accordingly, leading to pore throat narrowing or fracture closure accompanied by certain irreversible deformation damage, thus reducing permeability [21,22]. As shown in Figure 7a, with the increasing confining pressure, the permeability of the coal core decreased from 0.028 × 10⁻³ μm² to 0.002 × 10⁻³ μm²; the maximum permeability damage rate ranged from 92.86% to 100%. When the confining pressure reduced to 3.5 MPa, the permeability damage rate of coal rock ranged from 32.14% to 42.55%, indicating the sample is of strong stress sensitivity. As shown in the figure, during the pressure increase stage, the permeability of coal samples decreased with the increase in net confining pressure, with the initial decrease being much larger than the later stage, indicating the sample is of strong stress sensitivity (Figure 7b). During the pressure decrease stage, the permeability of coal increased with the reduction of net confining pressure, but it could not recover to the original permeability, indicating a moderate stress sensitivity due to irreversible permeability damage. Deep CEM reservoirs mainly consist of organic matter, clay minerals, calcite, and silica, and the development of microfractures. The deformation of clay minerals and microfractures is caused by the increased effective stress, which cannot return to the original state. Therefore, the drilling fluid density should be minimized to reduce the positive pressure differential between the drilling fluid column and the reservoir during the drilling in CBM reservoirs.

Proper control of drilling fluid density can prevent wellbore instability and reservoir damage while ensuring drilling safety. Maintaining the density within the window between formation pore pressure and fracture pressure helps avoid wellbore collapse and excessive fluid invasion, reducing pore blockage and permeability loss. In addition, strategies such as real-time monitoring and dynamic adjustment of drilling fluid density, as well as the introduction of anti-pollution and wettability-modifying agents, can further enhance reservoir protection.

3.3. Evaluation of Reservoir Protection Drilling Fluid

Based on the physical parameters of the deep CBM reservoir and potential reservoir damage analysis, the clay minerals in the Daning block are primarily kaolinite and illite–smectite mixed layers, which have certain hydration swelling properties. The coal is prone to spontaneous imbibition, resulting in liquid-blocking damage. Additionally, the reservoir rock exhibits water sensitivity, acid sensitivity, and stress sensitivity. Therefore, the drilling fluid for the deep CBM reservoir should be of good waterblocking prevention performance and compatibility with formation water.

(1)

Wettability alternation performance of anti-waterblocking agent

As shown in Figure 8, the contact angle of water droplets on the untreated coal sample surface is 25°. After treating the coal sample with different concentrations of the anti-waterblocking agent FSS solution, the contact angle of water on the core surface significantly increases. When the concentration of FSS is 1.0%, the contact angle of the water phase on the surface is 117°, indicating that the coal surface has changed from hydrophilic to hydrophobic, showing that the water phase is forming droplets on the coal surface. Therefore, FSS can achieve wettability alternation on the coal surface. This agent is a silicon-based surfactant; the Si-CH₃ group in the molecule structure plays a vital role in changing the surface wettability. The capillary force was altered from displacing force to resistance force, increasing the invasion difficulty of the liquid phase.

The experimental results shown in

Table 6. The effect of the increase of wetting angle on the desorption rate of coalbed methane was carried out in the experiment.

Contact Angle (°)	Gas Desorption Rate (mL/min)	Rate of Change in Desorption Rate (%)
25	1.05	0
98	1.32	25.71
105	1.43	36.19
109	1.51	43.81
117	1.59	51.43

indicate that as the contact angle increases, the coal surface changes from hydrophilic to hydrophobic. This reduction in the coal surface’s ability to adsorb water is conducive to gas desorption.

Through single-factor evaluation experiments, the contact angle and surface tension of coal samples were measured under varying concentrations of the anti-waterblocking agent. By conducting a comprehensive analysis, the optimal concentration of the agent was determined, ensuring that the wettability and surface tension of the coal samples reached the most favorable conditions for reservoir performance.

(2)

Effect of anti-waterblocking agent on spontaneous imbibition

Figure 9 shows the effect of the anti-waterblocking agent on the spontaneous imbibition. The water phase will spontaneously imbibe into the coal sample under capillary force. At the initial stage, the spontaneous water imbibition of coal significantly increased, reaching equilibrium after 200 min, and then the imbibition amount of water no longer increases. After adding FSS, the spontaneous imbibition amount of the coal decreases by 83.1%. Additionally, the spontaneous imbibition rate of the coal significantly decreases after adding FSS, showing a slow imbibition rate throughout the process. These experiments indicate that FSS can effectively reduce the imbibition of the water phase into the formation due to capillary force, thereby reducing the risk of waterblocking damage.

(3)

Low surface tension

Figure 10 shows the effect of the anti-waterblocking agent on the surface tension of solution. The initial surface tension of pure water is 72.15 mN/m. When the concentration of the anti-waterblocking agent FSS is 0.1%, the surface tension of the solution drops to 35.2 mN/m. When the concentration of FSS is 0.2%, the surface tension drops to 31.42 mN/m. As the concentration of the anti-waterblocking agent increases, the surface tension of the solution gradually decreases. When the concentration reaches 1%, the surface tension of the phase drops to 26.58 mN/m. Compared to OP-10 and SDBS, the prepared FSS has a stronger surface activity. According to the Laplace equation, the capillary force in the pore throat is proportional to the surface tension of the liquid phase: the greater the capillary force, the higher the flow resistance of the liquid phase in the capillary [23,24]. Therefore, the prepared anti-waterblocking agent can significantly reduce the surface tension of the liquid phase, thereby reducing the capillary force and mitigating the degree of waterblocking damage to the reservoir.

(4)

Permeability damage evaluation of coal sample

As shown in

Table 7. Experimental results of permeability recovery rate.

Sample	K0/(10−3μm2)	Solution	K1/(10−3μm2)	Permeability Recovery Rate (%)
Daning 5	0.003	Formation water	0.0013	56.6
Daning 5	0.003	1%FSS solution	0.0024	80.0

, the initial gas permeability of the core was 0.003 × 10⁻³ μm². After contamination with the formation water, the gas permeability was 0.0013 × 10⁻³ μm², and the permeability recovery rate was only 56.6%, indicating the coal suffered severe waterblocking damage. Another sample had an initial gas permeability of 0.003 × 10⁻³ μm²; after treatment with 1% FSS solution, the gas permeability of which was 0.0024 × 10⁻³ μm², the permeability recovery rate reached 80%, indicating the waterblocking damage was significantly reduced after treatment. Therefore, the prepared water-lock agent FSS can significantly restore reservoir permeability and effectively alleviate waterblocking damage.

(5)

The reservoir protection performance of Drilling Fluid

Based on the anti-waterblocking agent, a water-based drilling fluid system suitable for the deep CBM reservoir was constructed by optimizing plugging agents and lubricants. The formula is 4% bentonite + 1.0% FSS-1 + 0.5% inhibitor + 2% nano plugging agent + 1% PAC-LV + 2% SPNH (weighted with barite to 1.3 g/cm³). The comprehensive performance was evaluated. Figure 11 shows the effect of drilling fluid on the wettability of the sample. When the core was soaked in a 4% base slurry, the contact angle of the water phase on its surface is 23°, indicating the sample is of liquid wetting. After being treated by the optimized drilling fluid, the contact angle of the water phase on its surface reached 91°, showing good hydrophobicity.

As shown in Figure 12, the volume of the sample rapidly expands when water contacts bentonite cores, and the linear expansion rate reached 57.1% after 16 h. The polyamine drilling fluid with strong inhibition and the optimized drilling fluid initially have a low expansion rate when contacting bentonite cores, but the linear expansion rate of the polyamine drilling fluid reached 19.53% after 16 h. The optimized reservoir protection drilling fluid did not show significant expansion when contacting bentonite cores; the linear expansion rate was only 9.3% after aging 16 h, a significant reduction compared to the 57.10% with distilled water that can be observed. And the optimized reservoir protection drilling fluid shows that its anti-collapse performance is also better than the polyamine drilling fluid, indicating that the optimized drilling fluid has good anti-collapse performance. By reducing the expansion rate, the optimized drilling fluid decreases the risk of pore throats and microfractures within the reservoir rock closing or becoming blocked, thereby maintaining the stability of the pore structure and enhancing the anti-collapse properties of the coal reservoir.

The sand bed plugging experiment can be used to demonstrate the macroscopical plugging ability of drilling fluid. By measuring the invasion depth of drilling fluid in the sand bed, the plugging ability of drilling fluid can be qualitatively evaluated. Quartz sand with 20–40 mesh was loaded into the cup of a portable non-permeable fluid loss tester to 180 mL, and then 250 mL drilling fluid was added in. Under a pressure of 0.69 MPa, the invasion depths of three different drilling fluid systems in the sand bed were tested, and the results are shown in

Table 8. Plugging ability of drilling fluids in sand bed over times.

Drilling Fluid	Time/min	1	7.5	15	30
Polyamine drilling fluid	Depth/mm	18	20	20	20
Silicate drilling fluid	Depth/mm	16	17	17	17
Optimized drilling fluid	Depth/mm	5	6.5	6.9	7

.

As shown in Table 6, the invasion depths of the polyamine drilling fluid and silicate drilling fluid in the sand bed within 30 min were 20 mm and 17 mm under a pressure of 0.69 MPa, respectively. The invasion depth of the optimized drilling fluid system was only 7 mm under the same conditions; results show that the optimized drilling fluid is better than both of the polyamine and silicate drilling fluids. This indicates that all three drilling fluids are of certain plugging abilities, but the optimized drilling fluid exhibits a stronger plugging performance [25]. The strong blocking capability helps prevent excessive invasion of the drilling fluid, reducing disturbances to the reservoir pore channels [26,27]. By forming a stable barrier layer, the drilling fluid effectively isolates excess fluid invasion, preventing the formation of irreversible blockages and thereby enhancing the stability of the reservoir.

4. Conclusions

To address the severe reservoir damage during the drilling of the deep CBM reservoir, the potential reservoir damage mechanisms of the deep CBM reservoir were analyzed, and the ideas of wettability alteration and surface tension reduction were adopted to construct a reservoir protection drilling fluid suitable for the deep CBM reservoir, as follows:

(1)

The Daning block is developed cleats, the fractures mainly consisting of “bulbous” and “feather-like” microfractures. Mineral particles with micron size can easily block pore throats and fractures, and spontaneous imbibition in small fractures can cause liquid-blocking effects, leading to cumulative reservoir damage. The physical properties of the coal reservoir are poor, exhibiting small pore throat and strong capillary resistance. The detained fluids that enter the reservoir are more difficult to flow back, and waterblocking damage shows a greater impact on productivity than solid particle blockage.

(2)

When the concentration of the anti-waterblocking agent FSS varies from 0% to 1%, the surface tension of the water phase can decrease from 72.15 mN/m to 26.58 mN/m, and the maximum contact angle of water on the surface can reach 117°. The spontaneous imbibition amount and rate of the core significantly decrease, and the permeability recovery rate can be improved from 56.6% to 80.0%.

(3)

The optimized reservoir protection drilling fluid has good wettability alternation and inhibition, along with excellent plugging performance. It can effectively prevent the invasion of the water phase from the drilling fluid into the reservoir, which is crucial for protecting gas well productivity.