Study on Wellbore Instability Mechanism and High-Performance Water-Based Drilling Fluid for Deep Coal Reservoir

Abstract

Deep coalbed methane (CBM) reservoirs have the characteristics of low permeability, low porosity, and low water saturation, which easily experience wellbore instability due to drilling fluid, severely affecting drilling safety. Based on the physical property analysis of coal samples, the wellbore instability mechanism of the deep CBM reservoir was investigated by multiple methods. It was found that the wellbore instability is mainly caused by drilling fluid intrusion and the interaction between drilling fluid and coal formation; the fracture pressure of coal after immersion decreased from 27.4 MPa to 25.0 MPa because of the imbibition of drilling fluid. A novel nano-plugging agent with a size of 460 nm was prepared that can cement coal particles to form disc-shaped briquettes with a tensile strength of 2.27 MPa. Based on that, an effective anti-collapse drilling fluid for deep coal rock reservoirs was constructed, the invasion depth of the optimized drilling fluid was only 6 mm. The CT result shows that the number of fractures and pores in coal rock significantly reduced after treatment with the wellbore-stabilizing drilling fluid; nano-plugging anti-collapse agent in drilling fluid can form a dense layer on the coal surface, and then the hydration swelling of clay in the wellbore region can be effectively suppressed. Finally, the drilling fluid in this work can achieve the purpose of sealing and wettability alternation to prevent the collapse of the wellbore in the deep coal reservoir.

1. Introduction

China’s coalbed methane (CBM) exploration and development have entered the rapid expansion stage, establishing two major CBM production bases in the Southern Qinshui Basin and the eastern margin of the Ordos Basin [1,2], respectively. This marks a significant shift in exploration focus from high-rank to medium- and low-rank coals, while the development depth has extended from shallow reservoirs (<1000 m) to intermediate and deep formations (>1500 m). For CBM exploration efforts in regions deeper than 1500 m, daily gas production with horizontal well exceeds 1.0 × 10⁵ m³. The deep coalbed methane resources of China are approximately 30.4 × 10¹² m³ [3], which is crucial to the national energy structure, alleviating energy shortages under the strategy of reducing coal consumption, stabilizing oil production, and increasing natural gas utilization [4,5].

Coalbed methane, also known as coal seam gas, originates primarily from adsorbed gas on the surface of coal matrix particles; free gas in fractures; dissolved gas in coal seam water; and free gas trapped in thin sandstone, carbonate rocks, and other coal-bearing reservoirs. Unlike conventional natural gas, which requires large-scale migration before forming reservoirs, CBM is self-generated and self-stored within coal seams. This fundamental difference from conventional sandstone and carbonate reservoirs results in CBM’s unique characteristics, including high adsorption capacity, low permeability, and susceptibility to compression and fragmentation. These properties make CBM reservoirs prone to experience wellbore instability issues such as borehole collapse and lost circulation during horizontal drilling [6,7]. Furthermore, as drilling depth increases, the degree of coal metamorphism intensifies, water saturation decreases, temperature and pressure rise, porosity and permeability decline, and formation becomes more complex. These geological characteristics make deep CBM reservoirs more susceptible to wellbore instability compared to shallow formations, significantly impacting the safe and efficient development of coalbed methane resources.

Deep coal formations are highly brittle and weakly cemented, and they have strong pressure sensitivity, making them prone to collapse under pressure disturbances during drilling. Coal is susceptible to creep deformation, leading to fragmentation and instability. To mitigate these risks, drilling fluids should enhance wellbore stability and improve cementation strength [8,9]. Deep coal seams are characterized by well-developed cleats and microfractures, which facilitate the infiltration of drilling fluid filtrates through micropores, inducing a hydraulic wedge effect that weakens coal seam joints and triggers collapse. From a seepage mechanics perspective, improving the plugging performance of drilling fluids is essential to seal microfractures, reduce the permeability of seepage channels from the micron scale to the nanometer scale, and minimize filtrate invasion [10,11].

Deep CBM reservoirs exhibit strong heterogeneity due to the coexistence of multiple lithologies, including coal seams interbedded with gangue and carbonaceous mudstone [12,13]. The significant differences in mechanical and physicochemical properties among these lithologies exacerbate wellbore instability [14]. Over prolonged exposure to drilling fluids, the strength of coal–rock interfaces weakens, leading to interface instability between coal and gangue. Additionally, large volumes of free and desorbed gas trapped in deep coal formations invade the drilling fluid, causing a sudden drop in mud density. This initiates a vicious cycle of “wellbore instability–increased mud density–temporary stabilization–intensified filtrate invasion–worsening collapse”. To mitigate this issue, drilling fluids should enhance collapse resistance and reinforce interfacial strength. Moreover, due to the interbedded nature of coal, gangue, and carbonaceous mudstone, deep coal seams contain varying amounts of clay minerals, some of which are water-sensitive and prone to swelling upon hydration. This swelling exerts pressure on unconsolidated coal seams, leading to fragmentation, collapse, and wellbore instability.

To address these challenges, this study systematically analyzes the reservoir physical properties of deep coal formations in the Daning–Jixian block, identifies the key factors contributing to wellbore instability during deep coal drilling, and elucidates the wellbore instability mechanisms under the influence of drilling fluids. Based on the above study, a nano-plugging anti-collapse agent was prepared to seal microfracture, cement coal–rock, and stabilize wellbore. Then, an anti-collapse drilling fluid was developed for the deep CBM formations in the Daning–Jixian block, effectively resolving critical drilling challenges.

2. Experimental Section

2.1. Materials

Main reagents: Nano-based anti-collapse plugging agent (prepared in the laboratory). Anhydrous ethanol (AR), purchased from Shanghai Macklin Biochemical Technology Co., Ltd. (Shanghai, China). Rock samples sourced from the Daning–Jixian block, with a diameter of 2.5 cm and a length of 5–7 cm. Core samples are provided by the Daning–Jixian block, core slices (25 mm × 5 mm) and core (25 mm × 50 mm).

Main instruments: OCA-25 Optical Contact Angle Measuring Instrument, manufactured by Dataphysics, Stuttgart, Germany. ME104E Precision Balance, manufactured by Mettler Toledo, Zurich, Switzerland. LDY-180 Core Flow Apparatus, produced by Jiangsu Hai’an Petroleum Instrument Co., Ltd. (Nantong, China). Gemini 450 Scanning Electron Microscope (SEM), manufactured by Zeiss, Oberkochen, Germany. RTR-2000 High-Temperature, High-Pressure Rapid Rock Triaxial Testing System, developed by Beijing Shuangjie Te Technology Co., Ltd. (Beijing, China).

2.2. Characterization

(1)

Contact Angle Experiment

The coal core was cut into slices with a diameter of 2.5 cm and a thickness of 0.5 cm, using a core-cutting machine. Then, the slices were polished to a smooth surface with 800-grit metallographic sandpaper. The contact angle of distilled water on the core surface was measured using an OCA-25 optical contact angle measuring instrument [15].

(2)

Core Microstructure Characterization

The polished coal core slices were immersed in drilling fluid from the oilfield at a temperature of 120 °C for 16 h, and then they were removed and air-dried at a temperature of 25 °C. Scanning electron microscope (SEM) was used to analyze the microstructural changes before and after immersion. Additionally, the core slices were further polished to a smooth, level surface with 800-grit metallographic sandpaper, and a high-magnification metallographic microscope was employed to characterize the surface morphology of coal rock samples from the Jishen block.

(3)

Triaxial Mechanical Experiment

Two coal cores (25 × 50 mm) were selected for the triaxial mechanical experiment. Under a confining pressure of 2.5 MPa, the triaxial compressive strength tests were conducted on both a dry core (untreated with drilling fluid) and a wet core (immersed in drilling fluid at 120 °C for 16 h).

(4)

Sand-Bed Plugging Experiment

A portable zero-permeability filtration apparatus was used for the plugging experiment. First, 20–40 mesh quartz sand was poured into a transparent test cup up to the 180 mL mark, followed by the addition of 250 mL of drilling fluid. Under a pressure of 0.69 MPa, the invasion depth of both conventional anti-collapse drilling fluid and the newly developed anti-collapse drilling fluid was tested over time. The plugging performance of each system was evaluated based on the depth of fluid invasion into the sand bed.

3. Results and Discussion

3.1. The Physical Property Analysis of Deep Coal Reservoir

(1)

The clay mineral analysis of deep coal sample

The samples from Daning coal reservoir mainly consist of bright coal, followed by semi-bright coal; the texture of the sample is soft, and there is cleavage development, as shown in Figure 1. The content of clay in the coal samples ranges from 36.6% to 52.0%, and the average content is about 44.6%. The contents of clay minerals range from 48% to 2.2%, and the contents of illite and kaolinite are obviously high, as shown in

Table 1. XRD analysis of deep coal rock.

Sample	Type	Mineral Content%
		Quartz	Orthoclase	Plagioclase	Calcite	Analcite	Dolomite	Pyrite	Amorphous	Clay
1	Coal	/	/	/	23.4	5.6	/	2.4	32	36.6
2	Coal	39.2	/	/	5.2	/	/	7.4	10.0	38.2
3	Coal gangue	12.5	/	/	/	6.8	/	15.3	13.4	52.0
4	Coal gangue	7.2	/	1.5	4.7	/	/	/	35.0	51.6

and

Table 2. Clay minerals analysis of deep coal rock.

Sample	Type	Relative Content of Clay Minerals/%
		Smectite	Illite/Smectite	Illite	Kaolinite	Chlorite
1	Coal	/	/	82.7	17.3	/
2	Coal	/	/	92.8	7.2	/
3	Coal gangue	/	/	83.9	16.1	/
4	Coal gangue	/	/	67.5	32.5	/

. The non-expandable minerals primarily consist of quartz, calcite, and pyrite, among which the content of quartz is the most abundant. Consequently, the coal rock exhibits brittle characteristics, making it prone to crushing under the influence of external fluids. Additionally, the amorphous minerals within the pore throats would dissolve once contact was made with drilling fluid, leading to a reduction in the local structural integrity of the coal rock [16,17]. Therefore, the hard brittle minerals in coal rock are easy to break and block, thus affecting the wellbore stability.

(2)

The BET analysis of deep coal sample

The specific surface area and pore size distribution of the rock samples were determined using the BET (Brunauer–Emmett–Teller) adsorption method. The BET-specific surface area of the coal rock was measured to be 0.274 m²/g, with an average pore size of 25.61 nm, exhibiting characteristics of a Type II adsorption isotherm, as shown in Figure 2. The adsorption capacity initially increases rapidly before leveling off, followed by a sharp rise in the latter stage. This curve corresponds to an H4-type adsorption hysteresis loop, indicating the presence of narrow slit-shaped pores and fractures within the core [18].

(3)

The wettability evaluation of deep coal formation

The contact angle method was used to measure the water-phase contact angles on the surfaces of coal rock, sandstone, and shale, as shown in Figure 3. The contact angle of water on the coal surface was the highest, 84°, indicating the coal wettability has weak hydrophilicity; meanwhile, sandstone and shale exhibited strong hydrophilicity, the contact angles on which are 36° and 38°, respectively. During the drilling process, coal rock and interbedded gangue formations tend to spontaneously absorb drilling fluids, leading to the hydration swelling of clay minerals around the wellbore [19]. Additionally, the concentrated release of stress from hard and brittle minerals can result in wellbore instability and collapse.

3.2. Wellbore Instability Mechanism of Deep Coal Rock Reservoir

(1)

Effect of drilling fluid on coal surface morphology

The surface morphology of the coal sample before and after drilling fluid immersion was analyzed using the SEM technique [20]. The results indicate that the original coal sample exhibits a high surface roughness, with well-developed pores and microfractures, as shown in Figure 4a. A small amount of mud and sand can be observed filling the spaces between mineral crystals, and irregular particles are attached to the surface. After 16 h of immersion in drilling fluid, multiple fractures and an increased number of irregular particles (blue line) appear on the coal surface, as shown in Figure 4f, which can be attributed to the hydration and swelling of clay minerals within the pore–throat, leading to structural changes in the pores and throats. Additionally, as hydrated clay mineral particles swell and break into fragments, they detach from the coal rock surface, further altering its morphology.

(2)

Effect of Drilling Fluid on the Mechanical Properties of Coal Rock

Deep coal rock core samples with a size of 25 mm × 50 mm were selected for triaxial mechanical strength testing using the RTR-2000 High-Temperature, High-Pressure Rapid Rock Triaxial Testing System. The tests were conducted under a confining pressure of 2.5 MPa before and after immersion in drilling fluid. The drilling fluid soaking conditions were set at 120 °C for 16 h. Figure 5 shows the effect of drilling fluid immersion on the mechanical properties of coal rock. Figure 5a shows that the Sd-deviator stress of coal before immersion was 27.4 MPa, which decreased to 25.0 MPa after being immersed in drilling fluid. The fracture pressure experiences a significant reduction because of the imbibition of drilling fluid. Deep coal formations exhibit well-developed cleats and fractures, resulting in a large specific surface area. Due to capillary forces, drilling fluid filtrates easily infiltrate along these cleats and fractures, causing the hydration of clay minerals and simultaneously lubricating weak structural surfaces [21,22]. This leads to stress concentration along the cleat planes, reducing the strength of the coal rock. As a result, internal cracks propagate, extend, and spall, eventually leading to failure of the coal rock and gangue’s interfacial strength. As pore pressure increases, the deformation and instability of coal rock fragments around the wellbore become more pronounced, ultimately causing mechanical failure. Additionally, drill string collisions, tripping-induced scraping, and pressure fluctuations during drilling can further impact wellbore stability.

3.3. Synthesis and Evaluation of Nano Plugging Agent

(1)

The design of nano plugging agent

The nano-plugging agent with a size of 460 nm was prepared by the surface modification method. The synthesis procedure is as follows: Firstly, certain amounts of nano-silica, ethanol, and polyamine monomer were mixed in a flask; then, ethanol was dripped and stirred evenly at room temperature. Nitrogen was used to protect the product. The temperature was gradually increased to 75 °C, and azodiisobutylcyanide was placed in the solution as the initiator. The product was dried and grinded to prepare the nano-plugging agent. Figure 6 shows the synthesis routine and mechanism of the prepared nano-plugging agent. The nano-plugging agent can enter into the pores and cracks in the coal formation to form a compact adsorption layer to prevent the intrusion of drilling fluid.

Figure 7 shows the TG curve of the prepared nano-plugging agent. Three stages in the mass loss process of the agent can be observed when the temperature increases. The temperature of the first stage ranges from 25 °C to 185 °C, and the mass loss is about 1.41%. The mass loss can be ascribed to the loss of free water in the agent. As the temperature increases to 240 °C, the volatilization of crystal water in the molecule contributes to the mass loss of the nano-plugging agent [23]; the mass loss in this stage is about 17.8%. In the third stage, the mass loss of the agent was 16.5% when the temperature increased from 245 °C to 300 °C, and a sharp reduction in mass can be observed, which was mainly due to the thermal decomposition of amide groups in molecular chains, leading to a mass loss of agent. Generally, thermal degradation of the prepared agent occurs once the temperature exceeds 245 °C, indicating that the prepared agent is of favorable thermal stability.

As illustrated in Figure 8, the absorption peaks located at 3426 cm⁻¹ can be ascribed to the vibration of the C=O bond in the ester group of the plugging agent. The peak at 2885 cm⁻¹ can be assigned to the stretching vibration of -CH₂- in the molecular structure [24]. The peak at 1762 cm⁻¹ can be ascribed to the ester carbonyl absorption of polyurethane, and the stretching vibration absorption peak of the tertiary amide group C=O in polyurethane is observed at 1635 cm⁻¹ [25]. The characteristic absorption peak of the C-O-C bending vibration peak of the ester group in the polyurethane molecule appeared at 1141 cm⁻¹. The vibration peak of the C-N bond in the quaternary ammonium group of the prepared plugging agent is noted at 917 cm⁻¹ [26]. Notably, the strength of the characteristic peak increases with the increasing concentration of the agent.

(2)

Tensile strength test

In total, 5 g of coal particles with 10–20 mesh was evenly spread in a 3.4 cm diameter polytetrafluoroethylene (PTFE) mold. Subsequently, 5 mL of nano-plugging anti-collapse agent solutions with varying concentrations was added to the solution. The samples were then placed in an 80 °C oven and dried for 8 h. It can be observed that coal particles had formed disc-shaped briquettes with a certain degree of plasticity and strength, as shown in Figure 9a. Tensile strength tests were conducted on the coal sample, and the strength of coal sample increased to 2.27 MPa after being treated with 3% nano-plugging agent. However, the strength experienced a low decrease (1.854 MPa) with the increasing concentration of agent; the results are shown in

Table 3. The tensile test of the prepared nano-plugging agent.

Concentration/%	Rupture Force/N	Strength/MPa
0.0	-	-
0.5	176.572	1.625
1.0	154.811	1.785
3.0	166.907	2.272
5.0	146.937	1.854

. The control sample (without treatment) remained loose and did not undergo cementation. In contrast, coal samples treated with different concentrations of the nano-plugging anti-collapse agent solutions exhibited excellent cementation. The tensile strength of the cemented coal initially increased with the increasing concentration of the solution, followed by a decline, indicating that an optimal amount of the nano-plugging anti-collapse agent is 1.0%.

(3)

Surface Morphology Analysis Before and After Plugging

FE-SEM was used to observe the microstructural changes in the coal sample from the Jishen block before and after treatment, as can be seen in Figure 10. After treatment with the nano-plugging anti-collapse agent, a compact adsorption layer formed on the coal surface, and the nanopores and microfractures were effectively plugged (Figure 10c). This adsorption layer can prevent the invasion of drilling fluid into the deep coal formation. Hence, the hydration swelling of clay in the wellbore region can be effectively suppressed. Additionally, the plugging layer decreased stress transfer within the borehole wall and prevented borehole collapse caused by stress concentration. Therefore, wellbore integrity can be reinforced, significantly improving wellbore stability.

3.4. Evaluation of Anti-Collapsing Drilling Fluid

Based on the physical parameter analysis of deep CBM reservoirs and wellbore instability mechanism, we determined that the clay minerals in the Danning–Jixian deep CBM formation are primarily kaolinite and illite–smectite mixed layers, with a certain degree of hydration expansion. The coal is prone to spontaneous imbibition due to microcracks, thus weakening the coal strength. Therefore, the drilling fluid for deep CBM reservoirs should possess excellent plugging properties.

(1)

Rheological properties of the anti-collapsing drilling fluid

The rheological properties of drilling fluids for the deep CBM reservoir include appropriate viscosity, yield point, good shear thinning, and flow behavior. After fully considering the reservoir characteristics and optimizing the selection of thickeners and stabilizers, a series of experiments were conducted to form an optimized drilling fluid composition: 2% base slurry, 1% starch, 1% nano-plugging agent, 0.5% PAC-LV, 2% lignite, 1% white asphalt, 1% natural asphalt, 3% ultrafine calcium carbonate, and barite, as shown in

Table 4. The rheological properties of the constructed drilling fluid.

Apparent Viscosity (mPa·s)	Plastic Viscosity (mPa·s)	Yield Point (pa)	Flow Loss (mL)	φ6	φ3	φ310″/φ310
60	52	8.25	4	5	4	3.5/14

.

As can be seen from the above results, the apparent viscosity, plastic viscosity, and yield point of the constructed drilling fluid are 60 mPa·s, 52 mPa·s, and 8.25; thus, the drilling fluid exhibits excellent rheological properties, and the viscosity and yield point values meet the rheological requirements of CBM reservoirs. The flow loss is less than 4 mL, which effectively satisfies the requirements of rock carrying, wellbore cleaning, and filter cake formation properties for drilling fluid in the deep CBM reservoir.

(2)

Impact of anti-collapsing drilling fluid on the coal wettability

As shown in Figure 11, the contact angle of water on the untreated coal surface is 84°. After aging for different times, the variation in the contact angle of water on the coal surface remained minimal. When the aging time reached 24 h, the contact angle of water on the surface reached its maximum, at 89°, indicating that the coal surface still maintains weak hydrophilicity, making it difficult for water to spread on its surface. After aging for 72 h, the coal sample treated by the drilling fluid retained its hydrophilicity, and then the invasion of the drilling fluid caused by capillary force could be reduced.

(3)

Sealing performance of wellbore-stabilizing drilling fluid

The sand-bed plugging test effectively evaluates the sealing performance of drilling fluids on coal-bearing rock reservoirs. The invasion depth of drilling fluid in the sand bed reflects its interaction with the reservoir, which visually demonstrates the sealing efficiency of the drilling fluid, as can be seen in

Table 5. The plugging ability of drilling fluid at different times in sand bed.

Type	Time/min	1	7.5	15	30
Conventional drilling fluid	FL/mL	0	0	0	0
	Invasion depth/mm	16	18.5	18.5	18.5
The anti-collapse drilling fluid	FL/mL	0	0	0	0
	Invasion depth/mm	4	5.5	5.7	6.1

. Under a specific pressure for 30 min, the invasion depth of conventional drilling fluid in the sand bed was 18.5 mm. In contrast, the invasion depth of the optimized drilling fluid under the same conditions was only 6 mm. The experiment demonstrates that the drilling fluid in this paper exhibited a favorable sealing performance compared to conventional drilling fluid.

CT scanning experiments of coal samples before and after drilling fluid injection were conducted to extract the internal fractures [27,28], which can be used to evaluate the plugging performance of the drilling fluid, the blue represents the fractures, and the yellow represents the pore in the rock, as can be seen in Figure 12. After treatment with the wellbore-stabilizing drilling fluid, the fractal dimension of coal after being treated by the constructed drilling fluid increased from 2.3 to 2.1, indicating that the complexity of pores and fractures was reduced. The porosity of coal samples increased from 5.9% to 1.5%, and the number of fractures and pore volume within the coal rock significantly reduced, indicating that the drilling fluid exhibited good plugging performance, which can achieve the purpose of sealing micropores and fractures in the coal reservoir, preventing the collapse of the wellbore.

4. Conclusions

To address the wellbore instability issues during the drilling process in the deep CBM reservoir, the wellbore instability mechanisms of the deep CBM reservoir were investigated. A novel nano-plugging agent was prepared, based on the above study, and the drilling fluid with the feature of anti-collapsing for the deep CBM reservoir was constructed as follows:

(1)

The coal rock is prone to collapse under the interaction of drilling fluids. The amorphous minerals within the pore throats would dissolve once contact is made with drilling fluid, leading to a reduction in the local structural integrity of the coal rock. The radius of the pore throat is small, leading to a strong capillary force, and then the external fluid that can be imbibed into the coal rock becomes more difficult to flow back, further reducing the strength of the coal rock.

(2)

The prepared nano-plugging anti-collapse agent can effectively cement coal particles and fracture to stabilize the wellbore. The tensile strength of the coal briquettes increased to 2.27 MPa after being treated with the anti-collapse agent solution. The mechanism of the agent is that the nano-plugging anti-collapse agent forms a dense layer on the coal surface by sealing micropores and microcracks, and the adsorption layer can cement coal particles together. Hence, the hydration swelling of clay in the wellbore region can be effectively suppressed. Additionally, the plugging layer decreased stress transfer within the borehole wall and prevented the borehole collapse caused by stress concentration.

(3)

The drilling fluid for deep coal rock reservoirs was constructed, which exhibits excellent plugging and collapse prevention performance by plugging and wettability alternation. The invasion depth of the optimized drilling fluid in the sand bed was only 6 mm compared to that of conventional drilling fluid. The fractal dimension of untreated coal increased from 2.3 to 2.1, indicating that the complexity of pores and fractures was reduced. The porosity of coal samples increased from 5.9% to 1.5%, indicating that the drilling fluid exhibited good plugging performance, and the coal sample treated by the drilling fluid maintained hydrophilicity.

At present, the biggest challenge during the drilling process is wellbore instability, especially for long horizontal well drilling. Drilling fluid with a better capacity of plugging and anti-collapse is the guarantee for safe and efficient development of CBM reservoirs.