Experimental Study on the Effect of Drilling Fluid Rheological Properties on the Strength of Brittle Mud Shale

Abstract

To investigate the mechanism by which the rheological properties of drilling fluids affect the stability of the wellbore in brittle mud shale, this study systematically examines the influence of drilling fluids with different rheological properties on the hydration dispersion and rock strength of brittle mud shale through a series of laboratory experiments, including thermal rolling tests and uniaxial compressive strength tests on core samples. The results reveal that for weakly dispersible brittle mud shale, the rheological properties of drilling fluids have a minor effect on hydration dispersion, with rolling recovery rates consistently above 90%. However, the rheological properties of drilling fluids significantly influence the strength of brittle mud shale, and this effect is coupled with multiple factors, including rock fracture intensity index, soaking time, and confining pressure. Specifically, as the viscosity of the drilling fluid increases, the reduction in rock strength decreases; for instance, at 5 MPa confining pressure with an FII of 0.46, the strength reduction after 144 h was 69.8% in distilled water (from an initial 133.2 MPa to 40.2 MPa) compared to 36.3% with 3# drilling fluid (from 133.2 MPa to 88.7 MPa, with 100 mPa·s apparent viscosity). Both increased soaking time and confining pressure exacerbate the reduction in rock strength; a 5 MPa confining pressure, for example, caused an additional 60.9% strength reduction compared to 0 MPa for highly fractured samples (FII = 0.46) in distilled water after 144 h. Rocks with higher fracture intensity indices are more significantly affected by the rheological properties of drilling fluids. Based on the experimental results, this study proposes a strength attenuation model for brittle mud shale that considers the coupled effects of fracture intensity index, soaking time, and drilling fluid rheological properties. Additionally, the mechanism by which drilling fluid rheological properties influence the strength of brittle mud shale is analyzed, providing a theoretical basis for optimizing drilling fluid rheological parameters and enhancing the stability of wellbores in brittle mud shale formations.

1. Introduction

Wellbore instability in complex formations continues to pose a formidable challenge in oil and gas drilling engineering, leading to significant economic losses and operational risks [1,2,3]. Among these challenging lithologies, brittle mud shale stands out as a particular concern. Characterized by its inherently high brittle strength, prevalent natural fractures, and relatively weak water sensitivity, brittle mud shale presents unique stability issues distinct from conventional water-sensitive shales. Studies by scholars in China and abroad [4,5] indicate that the clay minerals in brittle mud shale are predominantly weakly hydrated illite–smectite mixed layer, illite, and chlorite, which are not prone to hydration dispersion upon contact with water. Their pore throats are mostly in the nanoscale range (1–100 nm), with an average pore throat diameter of 10–30 nm. Despite this weak water sensitivity, its inherent geological characteristics, particularly the presence of numerous closed or open bedding planes and pre-existing micro-fractures [6], render it highly susceptible to integrity loss during drilling operations. Once drilled, under the action of pressure differential and capillary pressure, drilling fluid filtrate can easily invade, causing the mud shale to crack along fracture surfaces or bedding planes. These cracks then continuously propagate both laterally and longitudinally along the fractures, leading to wellbore instability. During the drilling process, the combined effects of drilling fluid invasion [7] and disturbances in the surrounding stress on these geological weak planes lead to a reduction in rock strength and subsequently trigger complex downhole accidents such as wellbore collapse and falling debris [8,9,10]. Therefore, conducting an in-depth study on the interaction mechanism between drilling fluids and brittle mud shale and revealing the influence patterns of drilling fluid properties on the strength of brittle mud shale holds significant importance for optimizing drilling fluid performance and ensuring the stability of wellbores in brittle mud shale formations.

Drilling fluid, often dubbed the “blood” of drilling operations, is indispensable for the successful execution of drilling projects. Its diverse functions, ranging from bit cooling and lubrication to cuttings removal and wellbore stabilization, directly impact overall drilling efficiency and safety [11,12,13]. Beyond these conventional roles, the rheological properties of drilling fluid, as one of its key physicochemical attributes, exert a profound influence on its interactions with the subsurface formations. Specifically, rheology plays a significant role in its rock-carrying capacity, suspension capacity, pressure transmission, and interaction with the formation. For shale formations, the rheology of drilling fluid not only affects its ability to remove cuttings from the formation but may also influence the invasion speed, invasion depth, and contact area with the rock, thereby impacting the hydration dispersion and strength characteristics of the shale [14]. Recent advancements in drilling fluid technology include the development of nanotechnological additives for enhanced stability and filtration control, and the application of artificial intelligence for real-time wellbore stability prediction [15,16,17]. These innovations underscore the ongoing pursuit of optimizing drilling fluid performance.

Currently, research on the interaction between drilling fluids and shale formations primarily focuses on the hydration swelling, dispersion mechanisms of water-sensitive shale, and the development of inhibitive drilling fluids [18,19,20,21]. These studies have predominantly addressed challenges in highly hydratable shales, where osmotic effects and clay–water interactions are the primary drivers of instability. However, for brittle mud shale, due to its relatively weak water sensitivity, the traditional hydration dispersion mechanisms may not be the primary cause of wellbore instability. Consequently, a shift in research focus towards the mechanical degradation of these rocks is warranted. In recent years, some studies have begun to focus on the mechanical properties of brittle mud shale and the changes in its strength under the influence of drilling fluids [21]. Nonetheless, a critical gap exists in systematically investigating how drilling fluid rheological properties specifically influence the mechanical strength of brittle mud shale, particularly considering the complex interplay with intrinsic rock characteristics like fracture development, and extrinsic factors such as prolonged exposure (soaking time) and elevated confining pressures. Specifically, most prior work on brittle mud shales has focused on the stress damage mechanisms and general drilling fluid interactions [21], but a comprehensive, multi-factor investigation into how drilling fluid rheology specifically modulates the mechanical integrity of brittle mud shale, considering the coupled influence of pre-existing fractures, prolonged exposure times, and varying confining pressures, is lacking. This study aims to bridge this significant gap by providing a comprehensive, multi-factor analysis.

This study takes brittle mud shale as the research object and systematically investigates the influence of drilling fluids with different rheological properties on the hydration dispersion and rock strength of brittle mud shale through laboratory experiments. The research focuses on the variation characteristics of brittle mud shale strength under the coupled effects of drilling fluid rheology, rock fracture intensity index, soaking time, and confining pressure, while also analyzing the underlying mechanisms. The aim is to provide an experimental basis and theoretical support for the optimized design of drilling fluids in brittle mud shale formations, ultimately enhancing wellbore stability and reducing operational risks.

2. Experimental Materials and Methods

2.1. Experimental Materials

2.1.1. Drilling Fluid Formulation

The experiment designed three types of drilling fluids with different rheological properties, with the following formulations:

In the experiments, none of the three drilling fluids (see

Table 1. Drilling fluid formulation.

Num	Formulations
1# Drilling Fluid	3% bentonite + 0.2% NaOH + 0.3% XC (xanthan gum) + 0.6% PAC + balance distilled water
2# Drilling Fluid	3% bentonite + 0.2% NaOH + 0.3% XC (xanthan gum) + 1.2% PAC + balance distilled water
3# Drilling Fluid	3% bentonite + 0.2% NaOH + 0.3% XC (xanthan gum) + 2.0% PAC + balance distilled water

Note: The percentages are by weight (wt%), with the balance being distilled water.

) was added with brittle mud shale inhibitors, ensuring their inhibitory effects are comparable to water, in order to isolate and study the effects of rheology. The varied rheological properties were primarily achieved by adjusting the concentration of PAC (poly anionic cellulose), allowing for a focused study on viscosity’s impact while keeping other chemical interactions relatively consistent.

2.1.2. Experimental Samples

Samples used in the experiment are brittle mud shale cores, processed according to API RP 19TT [19] and ISRM suggested methods [20] to form cylindrical samples with a diameter of 50 mm and a height of 100 mm. The brittle mud shale samples were obtained from a deep shale gas reservoir in the Sichuan Basin, China. Efforts were made to select macroscopically uniform samples from a single block of shale to minimize natural heterogeneity, especially for comparative FII tests.

2.2. Experimental Methods

2.2.1. Determination of Rheological Parameters

The rheological parameters of distilled water and the three types of drilling fluids were determined using a ZNN-D6 type six-speed rotational viscometer (Qingdao Hengtada Mechanical and Electrical Equipment Co., Ltd., Qingdao, China). These parameters include apparent viscosity (AV), plastic viscosity (PV), yield point (YP), and others. Additionally, the API filtration loss was measured.

2.2.2. Hydration Dispersion Test

According to the API standard RP 13I [20], thermal rolling tests were conducted. Brittle mud shale cores were crushed and sieved to 16 mesh (1.0 mm) to 30 mesh (0.5 mm) particles. A sample of 50 g was weighed and subjected to thermal rolling tests in both distilled water and three types of drilling fluids with different rheological properties. The test temperature was 80 °C, and the duration was 16 h. The thermal rolling tests were performed using a ZJ-1 thermal roller, an industry-standard device with precise temperature and rotation control. After the test, the samples were sieved through a 40-mesh screen (0.425 mm), dried, and weighed. The rolling recovery rate was then calculated as the ratio of the final dried mass to the initial mass, expressed as a percentage:

(Final mass/Initial mass) × 100%.

2.2.3. Determination of Fracture Intensity Index

The fracture intensity index (FII) is a parameter representing the degree of internal micro-fracture development in rocks, specifically the relative change in P-wave velocity due to fractures [21,22]. Research has extensively studied the influence of drilling fluid rheology on the strength of brittle mud shale. However, the presence of numerous micro-fractures is a primary mechanical characteristic of brittle mud shale, necessitating research on the FII of brittle mud shale. For cores taken from the same rock sample, the FII remains consistent, as the cores are prone to fracturing under pressure. Even before reaching peak stress (i.e., prior to failure), the cores develop fractures, which can alter rock permeability. In this study, to measure the FII of brittle mud shale, a TAW-1000 pressure servo experimental system was used to perform uniaxial loading tests on brittle mud shale samples. The P-wave velocities (both axial and lateral) were measured during the loading process. The TAW-1000 system is a highly precise and calibrated apparatus standard for rock mechanics, ensuring reliable measurements. The FII is treated as a relative index within this study to characterize the comparative degree of micro-fracture development across our sample set under controlled loading conditions.

Rock when not loaded:

$$\sigma =E{\epsilon }_1^e$$

(1)

Rock after loading:

$$\sigma =E(1-FII){\epsilon }_2^e=\overline{E}{\epsilon }_2^e$$

(2)

where $\overline{E}=E(1-FII)$.

$$FII=1-{\displaystyle \frac{\overline{E}}{E}}$$

(3)

By solving Equation (3) simultaneously with $V_p=\sqrt{{\displaystyle \frac{E(1-v)}{\rho (1+v)(1-2v)}}}$, we obtain:

$$FII\approx 1-{(V_p/V_{p_1})}^2$$

(4)

where $V_p$ represents the P-wave velocity;

$V_{p1}$ denotes the P-wave velocity in the unloaded rock sample.

2.3. Experimental Steps

(1) Using the TAW-1000 pressure servo experimental system, standard rock cores were subjected to uniaxial loading to obtain rock core samples with different fracture intensity indices (0, 0.18, and 0.46).

(2) Rock cores with different fracture intensity indices were placed into distilled water and three types of drilling fluids with different rheological properties for soaking. The confining pressure during soaking was set to two conditions: 0 MPa and 5 MPa.

(3) After soaking for different durations (24 h, 72 h, and 144 h), the rock core samples were retrieved, and their uniaxial compressive strength (UCS) was measured.

3. Results and Discussion

Figure 1 illustrates the variation in the fracture intensity index (FII) during the loading of brittle mud shale. It can be observed that the FII calculated using lateral P-wave velocity increases with increasing stress, which aligns with the crack (micro-fracture) development pattern during rock compression. Although P-wave velocity commonly decreases with increasing damage, in certain loading conditions and for specific wave types (like lateral P-waves), the relative change in velocity (FII) can increase, reflecting the complex evolution of micro-fractures. However, the FII calculated using axial P-wave velocity shows negative values and an unreasonable variation pattern. This may be due to the restricted axial deformation of the rock during axial loading, leading to complex changes in the propagation path of axial acoustic waves and affecting the accuracy of FII calculations. Therefore, in this study, the FII calculated using lateral P-wave velocity is adopted to characterize the extent of crack (micro-fracture) development in brittle mud shale. The test results are shown in

Table 2. Rheological parameters of distilled water and drilling fluids.

No.	Initial Gel Strength (Pa)	Final Gel Strength (Pa)	API Fluid Loss (mL)	Apparent Viscosity (mPa·s)	Plastic Viscosity (mPa·s)	Yield Point (Pa)
Distilled Water	—	—	—	1	0	1
1#	2.5	4.0	10.0	25.5	15.0	10.5
2#	4.0	7.5	9.0	47.0	28.0	19.0
3#	7.5	12	6.0	100.0	60.0	40.0

.

3.1. Effect of Drilling Fluid Rheology on the Hydration Dispersion of Brittle Mud Shale

The results of the thermal rolling test, as shown in

Table 3. Results of thermal rolling test.

Fluid	Mass Before Experiment (g)	Mass After Experiment (g)	Rolling Recovery Rate (%)
Distilled Water	50	46.56	93.12
#1 Drilling Fluid	50	45.14	90.28
#2 Drilling Fluid	50	45.69	91.38
#3 Drilling Fluid	50	46.13	92.26

, indicate that the rolling recovery rate of brittle mud shale in distilled water and three types of drilling fluids with different rheological properties is above 90%, with little variation among the groups. This suggests that brittle mud shale belongs to a weakly dispersible formation, and the rheology of drilling fluids has a relatively minor effect on its hydration dispersion.

3.2. Effect of Rheology on the Strength of Brittle Mud Shale

Changes in the stress around the wellbore caused by drilling lead to stress damage and the generation of micro-cracks, resulting in variations in the fracture intensity index of the rock. Simultaneously, the drilling fluid invades the formation along these micro-cracks, affecting certain properties of brittle mud shale. The primary effects include increasing the fluid pressure within the micro-cracks and lubricating the fracture surfaces. However, the impact of drilling fluid with different rheological properties on the strength varies. Therefore, the extent of strength reduction in brittle mud shale after contact with drilling fluid is related to both the fracture intensity index of the rock and the rheological properties of the drilling fluid. Experimental results show that different applied stresses lead to different fracture intensity indices. Through loading, rock cores with relative fracture intensity indices of 0.18 and 0.46, as well as unloaded rock cores (FII = 0), were obtained.

According to the experimental method, brittle mud shale cores were soaked in different types of drilling fluids: distilled water, 1# Drilling Fluid, 2# Drilling Fluid, and 3# Drilling Fluid. The confining pressures during soaking were 0 MPa and 5 MPa, and the soaking times were 24 h, 72 h, and 144 h. The categories of brittle mud shale included unloaded, FII = 0.18, and FII = 0.46. The uniaxial compressive strength results after soaking are shown in

Table 4. Experimental results of the uniaxial compressive strength of hard brittle shale after immersion.

Type	Confining Pressure (MPa)	Soaking Time (h)	Strength Reduction (%)
			FII = 0
Distilled Water	0	24	5.8
		72	12.9
		144	12.5
	5	24	26.8
		72	42.8
		144	43.0
1# Drilling Fluid	0	24	5.1
		72	10.6
		144	11.2
	5	24	21.6
		72	31.5
		144	33.1
2# Drilling Fluid	0	24	6.2
		72	6.5
		144	9.2
	5	24	20.6
		72	26.9
		144	25.7
3# Drilling Fluid	0	24	3.2
		72	6.5
		144	4.8
	5	24	10.7
		72	17.2
		144	20.6

Initial UCS values: unloaded (FII = 0): 140.7 MPa; FII = 0.18: 135.6 MPa; FII = 0.46: 133.2 MPa.

. From the experiments, it was found that the reduction in the strength of brittle mud shale is related to the soaking time, type of drilling fluid, confining pressure during soaking, and the fracture intensity index of the brittle mud shale. Consequently, relevant expressions were obtained:

$$UCS=UC{S}_0-a\exp \left(b\cdot FII+{\displaystyle \frac{P_w}{c}}-{\displaystyle \frac{d}{t}}\right)$$

(5)

where $UCS$—uniaxial compressive strength of the rock core after soaking in the drilling fluid, $MPa$;

$UC{S}_0$—uniaxial compressive strength of the rock core before soaking, $\mathrm{M}\mathrm{P}\mathrm{a}$;

$a,b,c,d$—constant related to rock core properties, drilling fluid properties, and soaking confining pressure;

$FII$—the relative fracture intensity index of the rock core;

$t$—rock core soaking time, h.

$P_w$—confining pressure.

Based on Equation (5) and combined with experimental results for fitting, as shown in Figure 2, it was found that different soaking confining pressures and fracture intensity indices of the rock cores result in fitting curves that have good fitting results with the experimental values.

Based on the experimental results presented in Figure 3, Figure 4 and Figure 5, supported by the detailed data in Table 4, the following key observations and insights regarding the strength of brittle mud shale under the influence of drilling fluids are identified:

(1) Time-Dependent Strength Attenuation and Stabilization

The strength of brittle mud shale consistently decreases with increasing soaking time in drilling fluid. This reduction exhibits a characteristic pattern: the rate of decrease is initially high, particularly within the first 24 to 72 h, and then gradually slows until it approaches a relatively stable state, typically by the later soaking periods. For instance, for unloaded samples (FII = 0) soaked in distilled water at 0 MPa confining pressure (Figure 3), the strength decreased from an initial 140.7 MPa to 122.5 MPa after 72 h (a 13.0% reduction), while between 72 h and 144 h, the change was minimal (from 122.5 MPa to 123.1 MPa). This demonstrates an initial rapid fluid invasion and interaction, followed by a diminishing rate as equilibrium is approached.

(2) Confining Pressure’s Intensifying and Amplifying Role

An increase in confining pressure during soaking leads to a significantly greater reduction in the strength of brittle mud shale. Furthermore, an increase in confining pressure significantly amplifies the influence of drilling fluid rheology on the strength of brittle mud shale. For example, at 144 h soaking time for FII = 0.46 samples, distilled water led to a strength of 102.9 MPa at 0 MPa confining pressure (Figure 5), but only 40.2 MPa at 5 MPa confining pressure (Figure 5), representing a drastic additional 60.9% reduction in strength due to the increased confining pressure. This pronounced difference highlights that high confining pressure magnifies the rock’s susceptibility to fluid invasion effects. Moreover, the protective effect of higher viscosity drilling fluids becomes far more evident under 5 MPa confining pressure; for instance, at 144 h and 5 MPa, the strength of FII = 0.46 samples increased from 40.2 MPa with distilled water to 88.7 MPa with 3# drilling fluid, demonstrating that drilling fluid rheology plays a more critical role in maintaining wellbore stability in high-stress environments.

(3) Viscosity as a Strength-Preserving Factor

For drilling fluids with different rheological parameters, a clear trend is observed: the higher the viscosity (as detailed in Table 2, 3# > 2# > 1# > Distilled water r), the higher the residual strength of the brittle mud shale after soaking. This is consistently shown across Figure 3, Figure 4 and Figure 5 for all FII and confining pressure conditions. For example, considering the FII = 0.46 samples at 5 MPa confining pressure after 144 h (Figure 5), the strength ranged from 40.2 MPa (Distilled water) to 88.7 MPa (3# Drilling Fluid). This indicates that increased viscosity of the drilling fluid effectively mitigates the strength reduction, likely due to reduced fluid invasion, its superior fluid loss control, and reduced filtrate invasion into the rock matrix.

(4) Fracture Intensity Index: A Pre-existing Vulnerability

The reduction in uniaxial compressive strength of rock cores after soaking directly correlates with their initial fracture intensity index (FII). A higher FII, indicating a greater density of pre-existing micro-fractures, consistently results in a lower strength after soaking, and a proportionally larger strength reduction. This is evident across all soaking conditions. For instance, after 144 h of soaking in distilled water at 5 MPa confining pressure, the strength of FII = 0 rock (Figure 3) was 80.3 MPa, while for FII = 0.46 rock (Figure 5), it was only 40.2 MPa. This indicates that rocks with more developed internal fracture networks are intrinsically more vulnerable to fluid-induced degradation.

(5) Integrated Coupled Influence on Strength

A comprehensive analysis reveals that the strength of brittle mud shale after soaking is not influenced by individual factors in isolation, but rather by the complex coupled effects of drilling fluid rheology, confining pressure, fracture intensity index, and soaking time. Each factor interacts with and modulates the impact of the others. For example, the detrimental effect of high FII and prolonged soaking is significantly mitigated by high-viscosity drilling fluids, especially under elevated confining pressures. This multi-factor coupling underscores the necessity of a holistic approach to wellbore stability design in brittle mud shale formations.

3.3. Coupled Effects on the Attenuation Mechanism of Brittle Mud Shale Strength

Failure in brittle mud shale refers to a process where internal fractures continuously accumulate under stress conditions. Within the rock, micro-fractures gradually initiate, propagate, and connect as stress increases. When these micro-fractures accumulate to a critical extent, they form macro-fractures, leading to the failure of the rock.

Drilling will redistribute the wellbore stress and cause stress concentration. Under these conditions, brittle mud shale will generate micro-fractures. Simultaneously, the mechanical properties of the original micro-fractures change under the influence of drilling fluid. When the stress intensity factor at the tip of the original micro-fractures exceeds the fracture toughness of the brittle mud shale, the original micro-fractures will extend. When the extension reaches a certain degree, the micro-fractures connect, leading to a decrease in the rock’s bearing capacity and a reduction in its strength. According to the theory of fracture mechanics, assuming a plane strain condition, the stress intensity factor for a Mode I crack is expressed as follows:

$${\mathrm{K}}_{\mathrm{{\rm I}}}={\displaystyle \frac{1}{\sqrt{\frac{\pi L}{2}}}}{\displaystyle {\int }_{-\frac{L}{2}}^{\frac{L}{2}}p(x)\sqrt{\frac{L+2x}{L-2x}}}dx$$

(6)

where $L$— crack length, m;

$p(x)$—stress distribution on the crack surface, $MPa$.

From Equation (6), it can be seen that the stress intensity factor ${\mathrm{K}}_{\mathrm{{\rm I}}}$ of a Mode I crack is related to the stress distribution $p(x)$ on the fracture surfaces. The magnitude of $p(x)$ is primarily influenced by the fluid pressure $P_{fluid}$ within the fractures and is positively correlated with it. This indicates that the stress intensity factor ${\mathrm{K}}_{\mathrm{{\rm I}}}$ is affected by the fluid pressure $P_{fluid}$ within the fractures.

For unloaded brittle mud shale core samples, due to their low fracture intensity index and fewer micro-fractures, drilling fluids can only penetrate into pores and a small number of primary fractures. Since brittle mud shale exhibits poor water sensitivity, it barely reacts with drilling fluids. Consequently, the strength of brittle mud shale cores decreases only slightly with increased soaking time in drilling fluids. When the core samples are loaded, their fracture intensity index increases, resulting in numerous micro-cracks within the rock. Drilling fluids can now infiltrate into the rock through these micro-cracks, affecting its physical and chemical properties. Specifically, the lubricating effect of drilling fluids alters the roughness of micro-crack surfaces, enabling more internal fluid pressure to be transmitted to the crack tips. This increases the stress intensity factor, making micro-cracks more susceptible to extension. Additionally, the invasion of drilling fluid filtrate raises the pore pressure of the rock. The presence of numerous micro-cracks significantly enhances the filtration rate and pressure transmission efficiency, further increasing the degree of pore pressure rise. Therefore, the higher the fracture intensity index of the rock, the greater the impact of drilling fluids on its strength.

For rock samples with the same fracture intensity index, as the viscosity of the drilling fluid increases, the startup pressure gradient increases, thereby enhancing the resistance to the invasion of drilling fluid into the rock. Additionally, higher viscosity drilling fluids result in thicker boundary layers, reducing the size of fluid flow channels and weakening the pressure transmission effect. This indicates that as the viscosity of the drilling fluid increases, the disturbance to the formation fluid pressure within the fractures caused by the drilling fluid column pressure decreases, meaning the increase in internal fracture fluid pressure is smaller, and the degree of increase in the stress intensity factor at the fracture tips is relatively smaller, making micro-fractures less likely to extend and reducing the extent of rock strength reduction. This phenomenon is consistent with observations of superior fluid loss control and reduced filtrate invasion in high-viscosity drilling fluids, which minimizes their adverse effects on rock mechanical properties, although direct measurements of invasion depth were not performed in this study.

In summary, the reduction in the strength of brittle mud shale during drilling is the result of the coupled effects of multiple factors. The strength of the rock is influenced through the following mechanisms:

(1) Increased fluid pressure within micro-fractures: Drilling fluids invade the rock along internal micro-fractures, increasing the fluid pressure within the fractures. According to fracture mechanics theory, the stress intensity factor at the fracture tip is positively correlated with the fluid pressure within the fracture (Equation (6)). An increase in fluid pressure within the fractures leads to an increase in the stress intensity factor, promoting the extension and connectivity of micro-fractures, and ultimately reducing the rock strength.

(2) Lubrication effect on fracture surfaces: The invasion of drilling fluids may alter the roughness of fracture surfaces, creating a lubricating effect that reduces the friction between fracture surfaces. This makes it easier for fractures to slip and extend, thereby reducing the overall strength of the rock.

(3) Mechanism of drilling fluid rheology: High-viscosity drilling fluids have a higher startup pressure gradient, increasing the resistance to the invasion of drilling fluids into the rock and slowing down the invasion velocity and depth. Additionally, high-viscosity drilling fluids have thicker boundary layers, reducing the size of fluid flow channels and weakening the pressure transmission effect. Therefore, high-viscosity drilling fluids can slow down the increase in internal fracture fluid pressure, reduce the degree of increase in the stress intensity factor, and thus minimize the reduction in rock strength.

(4) Mechanism of fracture intensity index: Rocks with a higher fracture intensity index have more developed micro-fractures internally, providing more channels for the invasion of drilling fluids. Additionally, the presence of fractures increases the rock’s permeability, accelerating the invasion and pressure transmission of drilling fluids. Therefore, rocks with a higher fracture intensity index are more significantly affected by drilling fluids in terms of strength reduction.

4. Conclusions

Through systematic experimental studies, the effects of drilling fluid rheology on the hydration dispersion and strength of brittle mud shale were investigated, leading to the following main conclusions:

(1) For weakly dispersible brittle mud shale, the rheological properties of drilling fluids have a minor effect on hydration dispersion.

(2) The rheological properties of drilling fluids significantly influence the strength of brittle mud shale, and this effect is coupled with multiple factors, including the rock’s fracture intensity index, soaking time, and confining pressure.

(3) The rheological properties of drilling fluids significantly influence the strength of brittle mud shale. Higher drilling fluid viscosity effectively mitigates strength reduction, while increased soaking time, confining pressure, and higher rock fracture intensity indices all exacerbate strength loss due to coupled effects.

(4) A strength attenuation model for brittle mud shale was proposed, considering the coupled effects of fracture intensity index, soaking time, and drilling fluid rheology. This model effectively describes the strength variation pattern of brittle mud shale.

The findings provide a theoretical basis for optimizing drilling fluid rheological parameters, suggesting that higher viscosity fluids are more effective in mitigating strength loss, particularly in highly fractured formations and under elevated confining pressures, thereby enhancing wellbore stability in brittle mud shale formations. Future research could further explore the effects of other drilling fluid additives (e.g., nanoparticles) and incorporate microstructural analyses (e.g., SEM/EDS) to provide direct evidence of fluid invasion depths and their impact on rock fabric.