Research on Multi-Layer Drilling Mud Reuse Technology

Abstract

Addressing the issues of low reuse rates and high waste content of drilling fluids commonly observed in oilfields, research on reuse technology based on utilizing the same system across different sections of the same well has been conducted. Using the F oilfield as a case study, the mechanism of wellbore destabilization was investigated through X-ray diffraction and scanning electron microscopy. Corresponding inhibitory anti-collapse drilling fluids for shallow layers were formulated, and a successful deep drilling fluid formula was developed by adding and replacing chemicals in the base fluid, thereby achieving the reuse of multilayered waste drilling fluids. Indoor evaluation results indicate that the high-temperature rheology of the modified deep drilling fluid is reasonable; the high-temperature inhibitor performs excellently, with a 16-h rolling recovery rate of ≥98%; and the settlement stability is robust, with a settlement ratio of 0.50 after 2 h of resting. These findings demonstrate that the drilling fluid possesses both excellent sand-carrying capacity and strong inhibitory effects, meeting the requirements for rapid drilling and wellbore stabilization in this stratum. This technology is straightforward and easy to implement, and it is expected to reduce treatment costs and promote efficient development within the block.

1. Introduction

With the ongoing advancements in oil exploration technology, drilling processes in complex formations, deep wells, and ultra-deep wells have become increasingly common, thereby imposing higher demands on drilling fluid technology [1,2,3]. Concurrently, the enforcement of domestic environmental protection laws has led to stringent controls on drilling fluid discharge, making environmentally friendly drilling fluids and non-hazardous treatment technologies focal points of research in this field. To mitigate the ecological impact of waste drilling fluids, reduce the development costs of oil and gas wells, and enhance the utilization rate of drilling fluids, it is imperative to study drilling fluid utilization technologies [4,5]. The reuse of drilling fluid necessitates exceptional inhibition properties, allowing fine drill cuttings to disperse within the fluid with minimal hydration. Additionally, it must possess robust thermal stability to withstand the temperatures of deeper formations. Also, since the specific gravity of the drilling fluid is usually calculated by estimating the formation pressure from cable or real-time logs or by using available data from nearby neighboring wells and seismic surveys. However, these data may result in an improper estimation of formation pressure, resulting in the incorrect setting of drilling fluid density, leading to formation fluids entering the wellbore and stuck drilling [6]. Traditional drilling fluid reuse technologies predominantly employ solid control equipment to eliminate low-quality solid phases. This approach aims to recover used drilling fluids or mix them with fresh slurry in specific ratios to explore reuse potential. Zhang et al. [7] assessed the changes in drilling fluid properties over a 15-day period by utilizing samples from three wells at various stages of the horizontal section alongside freshly prepared slurry in the laboratory, considering the geological conditions of the Sulig gas field. The results indicated that the conventional properties of the drilling fluid remained consistent with those at drilling completion. The proportion of usable components was high, and despite changes in rheology, the filtration loss and bentonite content were within acceptable limits, making it suitable for dilute slurry reforming. It is projected that recycling 1 m³ of drilling fluid could theoretically reduce costs by approximately 300 RMB. Cheng et al. [8], addressing the practical drilling conditions in the Beibu Gulf area, developed a robust solid-phase control technology by analyzing particle sizes and testing the performance of waste drilling fluid. This equipment is capable of detecting the particle size distribution of solid-phase particles in the waste drilling fluid and optimizing the configuration and parameters of the solid control equipment. It effectively purifies the waste drilling fluid and dilutes it with an appropriate amount of new slurry, ensuring that the drilling fluid’s performance meets the requirements for subsequent wells or well sections. However, challenges such as low applicability, proportion control difficulties, and poor operability persist [9,10]. Therefore, this study focuses on different sections of the same well to investigate the feasibility of reusing drilling fluids by merely adjusting the type or quantity of chemicals.

The stratigraphic characteristics of the F oilfield block are primarily composed of lacustrine carbonate rocks and minor clastic rocks, with extensive development of mudstone and muddy dolomite, interspersed with sand and gravel from adjacent terrigenous sources [11,12,13]. During the drilling of shallow strata of sandstone, such as sand Section 1 and Section 3, which exhibit good permeability, thick mud cakes readily form. Combined with high mechanical drilling speeds, drill cuttings are not sufficiently purified in time, leading to sticking issues. In contrast, drilling in deeper layers such as sand (Section 4) involves abundant muddy dolomite characterized by microfractures. These dolomites readily absorb water, expand, and disperse, generating high hydration pressure and increasing the risk of collapse, thus complicating the drilling process [14,15,16]. Inadequate matching of drilling fluid performance often results in the formation of thick mud cakes and shrinkage blockages, compromising the stability of the wellbore. Significant volumes of drilling fluid are emitted during single mining processes, and the waste drilling fluid discharged to the surface is not effectively treated, leading to low reuse rates, poor economic returns, and severe environmental pollution [17,18]. Therefore, this study investigates the issues of imperfect drilling fluid matching and low recycling rates in this oilfield block. It includes conducting physical property tests on field-sampled cores, developing a drilling fluid system tailored to the shallow strata based on the analysis, and exploring the feasibility of reuse. Ultimately, the study aims to establish a set of drilling fluid reuse technologies that meet the development demands of the oil reservoir in this block.

2. Materials and Methods

2.1. Materials

The materials used in this study are shown in

Table 1. Experimental material types and manufacturers.

Material Name	Manufacturer
Core	The shallow and deep sections of oil field
bentonite	Zhejiang Fenghong New Material Co., Ltd., Huzhou, China
Aggravating agent	Wen’an Zhongde Chemical Co., Ltd., Langfang, China
CMC	Shandong Zhengyang New Material Technology Co., Ltd., Liaocheng, China
PAM	Shandong Zhengyang New Material Technology Co., Ltd., Liaocheng, China
KY-1 (Shale inhibitor)	College of Energy and Chemical Engineering, Jingzhou University, Jingzhou, China
KJ-1, KJ-2 (Fluid loss agent)	College of Energy and Chemical Engineering, Jingzhou University, Jingzhou, China
KZ-1, kZ-2 (Tackifier)	College of Energy and Chemical Engineering, Jingzhou University, Jingzhou, China
KN-1 (Viscosity reducer)	College of Energy and Chemical Engineering, Jingzhou University, Jingzhou, China

.

2.2. Equipment

The main instruments used in this study are shown in

Table 2. Types and manufacturers of experimental equipment.

Equipment Name	Manufacturer
Flip Type Pulper PJ-10L	Xianxian Tianjian Instrument Co., Ltd., Cangzhou, China
Mid-pressure Drilling Fluid Filter Press ZNS-2	Xianxian Tianjian Instrument Co., Ltd., Cangzhou, China
Rotational Viscometer D6B	Xianxian Tianjian Instrument Co., Ltd., Cangzhou, China
Shale Expansibility Tester KC-GDP1	Xianxian Tianjian Instrument Co., Ltd., Cangzhou, China
Liquid Density Meter YYM	Xianxian Tianjian Instrument Co., Ltd., Cangzhou, China
Roller Oven GRL-BX3	Qingdao Senxin Electromechanical Equipment Co., Ltd., Qingdao, China
Reaction Kettle LHG-3	Qingdao Senxin Electromechanical Equipment Co., Ltd., Qingdao, China
D/max 2500 X-ray Diffraction	Japan RIKEN Co., Ltd., Qingdao, China, Tokyo, Japan
Field Emission Scanning Electron Microscope	Hitachi, Japan, Beijing, China

.

2.3. Methods

2.3.1. Experimental Procedure

The appropriate amount of configured bentonite slurry was added to the drilling fluid cup, tap water was added and fixed onto the stirrer. Then, the speed was adjusted according to the formula, with the addition of shale inhibitor, flow regulator, viscosity increasing agent every 10 min. In addition, the filtration loss agent, aggravating agent, and viscosity reducing agent were all reduced, etc. After adding the chemicals and a duration of 30 min, the drilling fluid was configured for the performance test.

When the shallow drilling fluid is configured, 4% KY-1 (shale inhibitor) + 3.5% KJ-2 (fluid loss agent) + 0.25% KZ-1 (Tackifier) + 1.2% KN-1 (viscosity reducer) was added to the shallow drilling fluid formulation to make a deep drilling fluid. The full experimental flow of this paper is shown in Figure 1.

2.3.2. Basic Performance Testing of Drilling Fluids

(1)

Rheology and Filtration Loss Measurement

1)

The rheological properties and shear force of the drilling fluid were measured using a D6B six-speed rotational viscometer.

2)

While the API filtration loss was assessed with an NS-1 medium-pressure filtration loss meter. All experimental procedures were rigorously conducted in strict compliance with GB/T16783-1997 standards [19].

(2)

Expansion Rate Measurement

1)

A sample of 10.0 g of core powder, dried at (105 ± 2) °C for 4 h, was weighed, and the core was subsequently loaded into a core barrel and pressed at 10 MPa for 5 min to produce the test core.

2)

The core barrel was mounted on a shale expansibility tester KC-GDP1. The test liquid was then added to measure the change in core expansion height over time at room temperature, thereby evaluating the inhibition performance of the treatment agent and drilling fluid.

2.3.3. Analysis of the Well Wall Destabilization Mechanism

(1)

X-Diffraction Analysis

1)

X-diffraction was analyzed and tested using a D/max 2500 X-ray Diffraction. Approximately 3 g of core (dry weight > 5 g) was placed in a blast drying oven and dried at 45 °C for 24 h.

2)

After drying, samples for analysis were ground to 200 mesh, and the sediment was transferred to a 100 mL beaker, washed 2–3 times with deionized water, and placed in a vacuum desiccator to dry at 30 °C.

3)

The sample was then dried in a vacuum desiccator. The dried samples after de-drying were analyzed by X-ray diffraction.

(2)

SEM Analysis

1)

Scanning electron microscopy (SEM) was performed using a field-emission scanning electron microscope. The dried core was ground to below −5 μm, 2.0 g of core powder was weighed and placed into a beaker containing 40 mL of deionized water, and the pH was adjusted to 9.0.

2)

The sample was rinsed with deionized water 2–3 times and then placed in a vacuum drying oven at 30 °C for drying. The dried samples were examined by SEM.

2.3.4. Post-Conversion Performance Testing

(1)

Thermal stability

To make a deep drilling fluid 4% KY-1 (shale inhibitor) + 3.5% KJ-2 (fluid loss agent) + 0.25% KZ-1 (Tackifier) + 1.2% KN-1 (viscosity reducer) were added. The prepared drilling fluid is heated and rolled at 140 °C for 16 h. After completion of the heating process, the fluid is removed from the aging tank, and its rheological properties and filtration loss are tested.

(2)

Suspension stability

1)

The appropriate weight of deep drilling fluid was prepared to achieve the desired specific gravity.

2)

It was placed in a designated stainless steel tank and maintained at a specified temperature for a duration ranging from 2 to 24 h.

3)

The density or specific gravity of the upper (r₁) and lower (r₂) portions of the fluid column was then measured. The static settling factor (SF) was measured using formula (1). For example, if SF = 0.50, no static settling has occurred; if SF > 0.52, the static settling stability is considered poor [20].

$$SF={\displaystyle \frac{r_2}{r_1+r_2}}$$

(1)

where SF is the static sedimentation factor, r₁ is the density of the upper part of drilling fluid column, g/cm³, and r₂ is the density of the lower part of the drilling fluid column, g/cm³.

(3)

High Temperature Inhibitory

1)

The variable m₁g, was dried to a constant weight (105 °C ± 3 °C) of the core particles and placed in the reaction kettle containing the drilling fluid to be tested for hot rolling experiments.

2)

Approximately 16 h after incubation of the liquid in the tank, the rock samples were are all transferred to the aperture of a 0.42 mm subsampling sieve, in the tank containing tap water.

3)

The tap water was continuously replaced to wash the sieve, until the tap water is clear. The rock samples were transferred to a porcelain evaporating dish that had been dried and weighed, and together they were placed in a 105 °C ± 3 °C blast oven to dry to a constant weight (accurately to 0.1 g).

4)

The sample was then removed from the desiccator and cooled to room temperature and weighed (accurate to 0.lg), denoted as mass m₂. Three sets of parallel experiments were measured each time, and the average value was taken as the final result. The formula for calculating the heat roll recovery ω is shown in (2) [21].

$$\omega ={\displaystyle \frac{m_2-m_1}{m}}\times 100\%$$

(2)

where ω is the thermal roll recovery, %, m is the initial core particle mass, g, m₁ is the mass of the empty weighing bottle, g, and m₂ is the mass of core particles and weighing bottle after drying, g.

3. Results and Discussion

3.1. Analysis of the Well Wall Destabilization Mechanism

3.1.1. X-Diffraction Analysis

According to the “X-ray Diffraction Analysis Methods for Clay Minerals and Common Non-Clay Minerals in Sedimentary Rocks” (SY/T5163-2010), the mineral composition and clay content of rocks from the Sand III and Sand IV horizons were analyzed semi-quantitatively and quantitatively using a D/max 2500 X-ray diffractometer. The results are shown in Figure 2 and Figure 3. As illustrated in Figure 2 and Figure 3, the core samples are predominantly composed of clay, accounting for up to 50.00%. This is followed by sodium feldspar and quartz, constituting 24.37% and 19.77%, respectively, with minor amounts of potassium feldspar and calcite. The clay composition within the shale mainly consists of mixed layers of illite and montmorillonite, with some development of montmorillonite. Illite accounts for about 2%, and other clay minerals are present in smaller amounts. This indicates that these rocks have a strong hydration and swelling capacity, making it easy for drilling fluids to penetrate cracks upon contact with water-based drilling fluids, thereby increasing the stress intensity at the fracture tips. Microfractures gradually extend under high stress and external forces, reducing the effective stress around the wellbore. This further expansion of microfractures leads to wellbore instability [22].

3.1.2. SEM Analysis

From the results of X-diffraction analysis, it can be seen that the rock minerals are dominated by clay minerals, and the clay mineral composition is dominated by an aemon mixed layer, which indicates that the stratigraphic rocks are easy to be hydrated, causing the rock strength to decrease, resulting in the spalling and falling off of the well wall and destabilizing and collapsing. Therefore, in this section, the cores were immersed in water, and the microstructure of the immersed core surface was analyzed by a scanning electron microscope (SEM) to further investigate the destabilization mechanism.

The surface morphology of the core before and after water immersion is depicted in Figure 4. As illustrated in Figure 4, the mineral surface is rough, characterized by a few microcracks and powdery particles. The overall surface is angular, and the cohesion between minerals is tight (Figure 4a). After 24 h of water immersion, the surface of the mud shale core exhibits a fractured morphology, with a rough and irregular texture. This is attributed to the fact that water is prone to invade along the nano-micron pore cracks in the formation, causing reservoir damage, causing the hydration of clay minerals while increasing the pore pressure in the cracks, and exacerbating the collapse of the well wall to fall off the block (Figure 4b). Thus, the primary cause of well wall instability is the partial hydration and expansion of the clay in the rock samples [23].

3.2. Shallow Anti-Collapse Drilling Fluid Construction

3.2.1. Inhibitor Optimization

To address the issue of the mudstone in the shallow section easily forming slurry and to emphasize the strong inhibitory properties of anti-collapse drilling fluid, various inhibitory salts were evaluated for their inhibitory effects using a clay swelling experiment after the shallow core was pressed and sliced [24,25]. The experimental results are presented in Figure 5. As shown in Figure 5, the order of inhibitory effectiveness of the three inhibitors is NH₄Cl > KY-1 > Polyamine. However, due to the instability of NH₄Cl at high temperatures, which can easily decompose and produce irritating odor gases, KS-1, a high-temperature-resistant salt developed in the laboratory, is more suitable for this drilling fluid system. Consequently, KY-1 was selected as the inhibiting salt [26,27].

3.2.2. Tackifier Optimization

During the drilling operation, to ensure that the drill cuttings are flushed from the bottom of the well and carried up to the surface, and to smoothly transfer the pumping horsepower to the water hole of the drill bit to break the rock, the selected drilling fluid must have good rheological properties, such as appropriate viscosity, dynamic plasticity ratio, and shear dilution. Therefore, the selected drilling fluid must have good rheological properties, such as appropriate apparent viscosity, dynamic plastic ratio, and shear dilution. Adding the necessary viscosity builder to the base stock is a key factor in upgrading the drilling fluid. Adding the necessary viscosity builder to the base stock is one way to improve the rheology of the drilling fluid [28,29]. The addition of viscosity builders can enhance the rheology of drilling fluid. Using a 3.0% base slurry as the foundation fluid, various types of viscosity builders were added to optimize the performance of the viscosity enhancer. The experimental results are presented in

Table 3. Comparison of properties of different tackifiers.

Tackifier	Content	AV/mPa·s	PV/mPa·s	Gel/Pa	YP/Pa	YP/PV	n
KZ-1	0.25%	21.0	13.0	1.79	8.19	0.63	0.53
KZ-2		12.0	8.0	1.02	4.09	0.51	0.58

. As indicated in Table 3, KZ-1 exhibits a more significant viscosity-enhancing effect compared to KZ-2. Therefore, KZ-1 was selected as the primary viscosity-enhancing agent for the anti-collapse drilling fluid.

3.2.3. Shallow Drilling Fluid System Formulation

A set of high-performance drilling fluids for shallow formations was formulated by preferentially selecting two primary treatment agents and combining them with a conventional salt-resistant filter-loss reducer, a flow regulator, and other functional treatment agents. The formulation consists of 3% bentonite + 0.2% flow regulator + 3.5% KJ-1 + 1% KY-1 + 0.25% KZ-1 + 2.5% weighting agent (density = 1.400 g/cm³). The basic performance metrics are presented in

Table 4. Optimized formulation system and basic performance of raw collapse drilling fluid.

Aggravating	AV/mPa·s	PV/mPa·s	YP/Pa	YP/PV	n	FLAPI/mL	ρ/g/cm3
Weighted	28.0	22.0	6.16	0.28	0.72	5.2	1.073
Unweighted	47.5	37.5	10.13	0.27	0.72	4.0	1.401

[30,31].

As demonstrated in Table 4, the filtration loss of the weighted anti-collapse drilling fluid meets the basic requirements for field drilling construction (≤4.0 mL). Additionally, the plastic viscosity increased slightly after weighting; however, this did not impact the overall sand-carrying capacity.

3.3. Feasibility Study

Transitioning from shallow to deep involves higher clay mineral content and formation temperatures, necessitating stricter requirements on drilling fluid rheology, filtration loss, and anti-collapse performance. Consequently, there is a heightened demand for temperature resistance and inhibitors [32,33]. Hence, the transformation strategy is outlined as follows: ① Introduce new inhibitors or increase the dosage of existing inhibitors to enhance the inhibition and anti-collapse capabilities of the drilling fluid. ② Utilize the high-temperature composite viscosifier KZ-1 to enhance sand suspension and rock transport in the drilling fluid at elevated temperatures. ③ Incorporate a suitable amount of viscosifier to mitigate issues such as high-temperature dispersion, agglomeration, and passivation induced by elevated drilling fluid temperatures, thereby enhancing rheological properties and viscosity. ④ Employ a new high-temperature compound viscosity builder to enhance rheology, reduce filtration loss, and enhance anti-collapse performance, thereby improving overall rheological properties and viscosity. Replace the original KJ-1 filter loss reducer with the new temperature-resistant KJ-2 filter loss reducer to satisfy requirements for drilling fluid rheology, water loss control, formation stability, and anti-collapse properties at high temperatures [34,35].

3.4. Evaluation of the Performance of Deep Anti-Collapse Drilling Fluids

3.4.1. Thermal Stability Evaluation

Because the application depth of the new anti-collapse drilling fluid is about 4200 m, the experimental setting temperature is 140°. The new anti-collapse drilling fluid is hot rolled at 140° for 16 h and then taken out, cooled down to room temperature, and then the high-temperature rheological properties are measured, and the experimental results are shown in

Table 5. Comparison of the performance of new anti-collapse drilling fluids before and after hot rolling (140 °C).

State	AV/mPa·s	PV/mPa·s	YP/Pa	YP/PV	n	FLAPI/mL	FLHTHP/mL
Before	78.5	75.0	7.50	0.10	0.94	4.1	/
After	75.0	69.0.	6.90	0.10	0.89	3.0	9.5

and Figure 6.

As shown in Table 5, the viscosity of the new anti-collapse drilling fluid did not change much after hot rolling at 140 °C, and the filtration vector was reduced from 4.1 mL to 3.0 mL, which indicates that the configured new slurry has a better filtration loss and wall-making, and its rheology and rock-carrying capacity are in line with the construction requirements. Meanwhile, from the high temperature and high pressure water loss of 9.5 mL and the mud cake diagram (Figure 6), it can be seen that the mud cake is thin and dense, indicating that the addition of an anti-temperature and filtration loss reducer effectively plugs the tiny pores in the drilling fluid, and it can reduce the infiltration of filtrate into the formation to meet the needs of the site.

3.4.2. Suspension Stability Evaluation

Settlement stability reflects the ability of the weighting agent particles in the weighted drilling fluid to maintain uniform distribution in the drilling fluid [36]. The new anti-collapse drilling fluid was weighted to the target density (ρ = 1.540 g/cm³) in a beaker. The suspension stability was determined using the experimental method described in Section 2.3.3, with the results presented in

Table 6. Suspension stability after weighting of new anti-collapse drilling fluid.

ρtop (g/cm3)	ρbottom (g/cm3)	SF
1.540	1.540	0.50
1.540	1.541	0.50

. As shown in Table 6, the weighted drilling fluid exhibits excellent suspension stability; after standing for 2 h, there is no change in the specific gravity between the upper and lower layers, and the static settling factors remain at 0.5 [37,38,39]. As a result, the converted drilling fluid has better suspension stability and can effectively carry drill cuttings, purify the borehole, and keep the well wall stable.

3.4.3. Evaluation of Suppression Performance

High-temperature inhibition can respond to the guarantee that the drilling fluid can function properly in deep-well operations [40]. The transformed deep drilling fluids were measured using the experimental method in Section 2.3.2. The 140 °C core rolling recoveries of the new anti-collapse drilling fluid are presented in Figure 7. As shown in Figure 7, the drilling fluid exhibits excellent inhibition, with hot rolling recoveries exceeding 98%. This indicates that the converted drilling fluid maintains strong inhibition under simulated high-temperature (140 °C) conditions. It indicates that the anti-temperature inhibitor in the transformed anti-temperature anti-collapse water-based drilling fluid can inhibit the dispersion of mud shale hydration for a longer period of time, suggesting that it has excellent shale hydration inhibition properties.

3.5. Comparison with Previous Studies on Innovativeness

The innovative nature of this paper can be more easily understood by comparing it with previous similar studies. Therefore, a list form was used to compare this study with previous studies, and the results are shown in

Table 7. Comparison of this study with previous research methods.

Research Object	Technical Approach	Advantage	Disadvantage
Previous study	Mixing the old pulp with the new pulp proportionally	Works well with two different wells, more mature technology	Low applicability, difficult scale control, poor maneuverability, and economy
Our study	Addition of original/replacement agent to old pulp	Simple operation, good economy, applicable to different sections of the same well	Technology universality needs to be proven

. As illustrated in Table 7, this study markedly diverges from previous research in terms of technical implementation methods, applicability, and respective advantages and disadvantages. The prior research predominantly involved the proportional mixing of old and new slurry. In contrast, this study focuses on the reuse of old drilling fluid slurry by enhancing the dosage and adjusting the type of original formulated agents. Additionally, due to the varying performance requirements of drilling fluids across different wells, the previous study’s control over the ratio of old to new slurry posed challenges in terms of applicability and economic feasibility. This study utilizes shallow and deep drilling fluids from the same well as experimental subjects. The direct addition and replacement of dosages and chemicals simplifies operation and enhances economic efficiency for the same well. However, the feasibility of this method across different wells requires validation through subsequent research.

4. Conclusions

(1)

Through X-diffraction and scanning electron microscopy, the cause of well wall instability was clarified to be that the rock physical properties of the formation were mainly immonite and the mud shale reservoir was prone to hydration and expansion, which led to well wall instability;

(2)

The key treatment agents, such as shale inhibitor and viscosity builder, were selected to develop a shallow anti-collapse drilling fluid formula for the F oilfield block: 3.0% bentonite + 0.2% flow regulator + 3.5% KJ-1 + 1% KY-1 + 0.25% KZ-1 + 2.5% weighting agent (ρ = 1.400 g/cm³), and at the same time, a weighting agent (ρ = 1.400 g/cm³) was developed, and based on this formulation, the idea of reuse by increasing the concentration or replacing the agent was proposed;

(3)

The shallow anti-collapsing drilling fluid formula of F oilfield block was converted into a deep drilling fluid formula by adding 4% KY-1 + 3.5% KJ-2 + 0.25% KZ-1 + 1.2% KN-1, and the performance evaluation results showed that the converted deep drilling fluid formula had good high-temperature stability and suspension stability at 140 °C, and it had certain value for field application.

(4)

The future drilling fluid reuse technology should focus on the development of different high-performance temperature-resistant materials with a high degree of synergistic effect. While ensuring the performance requirements of drilling operations, the reuse process should be simplified as much as possible by increasing the dosage of the original agent of the old slurry or replacing the agent, so as to ensure the feasibility and economy of the field operations.