Synthesis of Poly(styrene-vinyl sodium sulfonate-butyl acrylate-ethyl methacrylate) and Its Blocking Mechanism as a Nanometer Material in Water-Based Drilling Fluid

Abstract

Nano-blocking technology has become a key to overcoming a prominent bottleneck in shale gas development. In this paper, poly(ST-VS-B-E) was synthesized by Michael addition reaction using styrene, vinyl sodium sulfonate, ethyl methacrylate, and butyl acrylate. Poly(ST-VS-B-E) was characterized by infrared spectroscopy analysis, laser scattering analysis, and thermogravimetric analysis. The rheological properties of drilling fluid with poly(ST-VS-B-E) were studied by testing the drilling fluid’s properties. The results showed that the median particle size of poly(ST-VS-B-E) was 79.15 nm and it resisted a 359.25 °C high temperature. The yield point of the water-based drilling fluid with 2.5 wt% poly(ST-VS-B-E) added was 27 Pa, and the fluid loss was 3.1 mL, with good drilling fluid performance. Further test results from simulated mud cake filtration and the simulated core penetration showed that when the mass concentration of poly(ST-VS-B-E) was 2.5 wt%, the blocking rates were 66.67% and 93.33%, respectively, and the blocking performance increased gradually with the addition of poly(ST-VS-B-E). Poly(ST-VS-B-E) can be squeezed into the nano-pores of a shale formation under the action of pressure difference, so as to block the formation and prevent the entry of water-based drilling fluid filtrate. Poly(ST-VS-B-E) can serve as a potential nano-blocking material in water-based drilling fluids.

1. Introduction

As commercial clean energy, shale gas is a focus of energy development that has good exploration and development prospects [1]. With the exploration and development of unconventional hydrocarbon resources [2], the exploitation of oil and gas resources using horizontal wells of shale gas has become an important means of oil and gas development [3]. However, most horizontal shale gas wells are designed to increase oil and gas seepage channels [4,5], and there are a large number of natural micro- and nano-pores and fractures in shale formations [6,7,8]. Therefore, the filtrate of water-based drilling fluids will penetrate into the micro/nano pores and fractures of the shale formation, weakening the structural force of the borehole wall and leading to serious instability, which causes the borehole wall to break and collapse [9,10,11,12,13]. At present, although some research has been conducted on water-based drilling fluid-plugging materials that can alleviate the problem of wellbore instability, most commonly used plugging materials are rigid, and the plugging layer they form is easily washed off by drilling fluid, which seriously disturbs the plugging effect [14,15,16]. Therefore, synthesizing a flexible nanomaterial for water-based drilling fluid is an effective measure to solve the problem of wellbore instability during drilling.

In recent years, researchers have been working on enquiries into nanoscale blocking materials and have achieved certain results. Xinliang Li et al. synthesized polymer nanospheres (PNS) with an average particle size of 133 nm, which can effectively seal the shale pores. However, the adverse effect of the blocking materials on the rheological properties of drilling fluid is a technical difficulty that needs to be overcome [17]. Lashkari Reza et al. synthesized an intelligent memory polyurethane (SMPU) that can deform with temperature. The synthetic SMPU can smoothly pass through the bit nozzle and alter its original shape to a temporary one by changing the temperature so as to effectively block the pores of the well wall and prevent the drilling fluid filtrate from penetrating into the formation [18]. Li and Wuquan et al. synthesized styrene–butadiene resin/silica nanoparticle (SBR/SiO₂) composites via continuous emulsion polymerization. SBR/SiO₂ can be dispersed in water and mineral oil, and its temperature resistance is 352 °C. The average particle size of the water phase is 62.4 nm, and the average particle size of the oil phase is 265.1 nm. SBR/SiO₂ can enter the nano-pores of shale reservoirs, significantly reducing fluid intrusion and improving wellbore stability [19]. Liu F et al. pointed out that drilling in porous and water-sensitive shale with water-based drilling fluids will lead to wellbore instability. A two-dimensional nanomaterial (Laponite) was used as blocking material, which can resist a high temperature of 150 °C and block the well. Laponite blocking materials can effectively prevent the penetration of free water into the nano-fractures of 10 nm~100 nm shale, and the plugging effect is excellent. However, the blocking materials can only resist a high temperature of 150 °C and cannot be used in deep wells and ultra-deep wells with higher temperatures [20]. Peixu Li et al. prepared a polymer lotion (NPE) to solve the problem that conventional blocking strategies were unable to seal microporous shale joints. The particle size range of NPE is 75 nm~240 nm, which can effectively block the microporous joints of shale and improve the stability of shale wellbores [21].

All these studies provide new directions for the development of blocking materials, but most of the blocking materials need to be improved in their physical and chemical properties. Therefore, the research for a high-performance nanometer blocking material is the key to improving wellbore stability. Poly(ST-VS-B-E) synthesized using the Michael addition reaction technique can be used to solve the wellbore instability problem in shale formations. Poly(ST-VS-B-E) has excellent temperature resistance and blocking performance, while having little effect on water-based drilling fluid performance. In order to lessen downhole complexity, poly(ST-VS-B-E) can be added to water-based drilling fluids as a superb nano-blocking material.

2. Materials and Methods

2.1. Materials and Instruments

Experimental materials: sodium dodecyl sulfate (K12), vinyl sodium sulfonate (VS), styrene (St), ethyl methacrylate (EMA), butyl acrylate (BA), divinylbenzene (DVB), ammonium persulfate (APS), and anhydrous Na₂CO₃ were obtained from Chengdu Xuya Innovation Technology Co., Ltd. Anti-temperature and filtrate reducers (HF-1, SMP-1, SMC) and micron barite were obtained from Chengdu Ruijixing Chemical Co., Ltd. The simulated core was from Chengdu Keping Technology Co., and we obtained bentonite from Xinjiang Zhongfei Xiazijie Bentonite Co., Ltd.

Experimental instruments: The particle size distribution of the nanomaterials was measured using a laser scattering system (BI-200SM) from Brookhaven Instruments (New York, NY, USA). A scanning electron microscope (Quanta450) from FEI Company was used to test the microscopic morphology of the simulated mud cake. The characteristic functional groups of nanomaterials were tested using an American Thermoelectric Company Fourier infrared spectrometer (Nicolet 6700) from America. The rheological properties of the water-based drilling fluid and the sealing performance of the nanomaterial were tested using a six-speed rotary viscometer (ZNN-D6) and a high-temperature and high-pressure filter (GGS42-2A) from Shandong Meike Instrument Co., Ltd. The thermal resistance of the nanomaterials was tested using TGA/DCS1 (MATTLER, Switzerland). The blocking performance of the nanomaterials was tested using an SCMS-C4 HTHP tight core permeability device (20172034-1) from Chengdu Haohan Completion Rock Electric Co., Ltd.

2.2. Synthesis of Nanomaterials

Weigh some sodium dodecyl sulfate and vinyl sodium sulfonate. Place into a three-neck flask with a capacity of 500 mL, add ultrapure water to dissolve them, raise the temperature to 40 °C, stir until dispersion, and pass nitrogen gas to react for 3 h, then raise the solution to 45 °C. Add styrene, ethyl methacrylate, butyl acrylate, and divinylbenzene slowly dropwise, using a constant-pressure dropping funnel, and place the three-necked flask in a constant temperature after the reaction is complete. Allow the solution to stand for 20 min and add a small amount of ultrapure water containing ammonium persulfate slowly dropwise, using a constant-pressure dropping funnel, warmed to 65 °C, and react under the condition of nitrogen gas for 8 h to obtain poly(ST-VS-B-E).

2.3. Blocking Performance Test

2.3.1. Filtration Test with a Simulated Mud Cake

We used 6 wt% pre-hydrated soil slurry + 3 wt‰ anhydrous Na₂CO₃ + 5 wt% SMP-1 + 5 wt% SMC + 1.5 wt‰ HF-1 to adjust the density to 1.17 g/cm³ by adding micron barite to make drilling fluid. The mud water-based drilling fluids prepared above was added to the HTHP filter, and the simulated mud cake was prepared after 0.5 h filtration under HTHP conditions (150 °C, 3.5 MPa). The permeability of the simulated mud cake was measured by HTHP filtration and a water-loss device. Then 1 wt%, 1.5 wt%, 2 wt%, 2.5 wt%, and 3 wt% poly(ST-VS-B-E) solutions were added to the HTHP (150 °C, 3.5 MPa) water-loss device to test the permeability of the mud cake after adding different concentrations of blocking materials. The experiment lasted for 0.5 h, and water loss was recorded every five minutes. The actual thickness of the mud cake was measured by micrometer; the permeability of the simulated mud cake was calculated by Equation (1) according to Darcy’s law, as well as the permeability of the simulated mud cake after adding poly(ST-VS-B-E) solution with different concentrations.

$$K=\frac{100Q\mu L}{A\mathsf{\Delta }P}$$

(1)

In the formula: K—permeability of the simulated mud cake, mD. Q—average volume of water loss per second, cm³/s. μ—viscosity of the filtrate, mPa·s. L—thickness (or length) of the mud cake, cm. A—area of the filter cake, cm². $\mathsf{\Delta }P$—filter loss differential pressure, MPa. The area of the filter cake = 23.8 cm²; filter loss pressure difference = 3.5 MPa.

2.3.2. Simulated Rock Core Permeation Experiment

An amount of 300 mL of 2.5 wt% poly(ST-VS-B-E) solution was ultrasonically dispersed for 0.5 h. The dispersed poly(ST-VS-B-E) solution was added to the SCLS-C4 HTHP tight core permeability testing device, and the permeability of poly(ST-VS-B-E) in the simulated core permeability test was evaluated under HTHP conditions (105 °C, 3.5 MPa). The calculation formula of the simulated core permeability is shown in Equation (1) of Section 2.3.1.

3. Results and Discussion

3.1. Characterization

3.1.1. Infrared Spectrum

The chemical structure of a substance can be inferred from the functional groups reflected in the spectrogram of Fourier infrared spectroscopy. Figure 1 is the infrared absorption spectrum of poly(ST-VS-B-E). The wave peak at 1635 cm⁻¹ is the tensile vibration peak of the benzene ring. The peak at 669 cm⁻¹ is the external deformation vibration peak of C-H on the benzene ring. The wave peak at 1488 cm⁻¹ is the symmetric variable angle vibration peak of -CH₃. The wave peak at 1270 cm⁻¹ is the asymmetric tensile vibration peak of S=O of sulfonate and the antisymmetric tensile vibration peak of C-O-C. The wave peak at 1051 cm⁻¹ is the symmetric tensile vibration peak of sulfonate. The functional groups mentioned above demonstrate that poly(ST-VS-B-E) was successfully synthesized [22,23].

3.1.2. Grain Size Distribution of Poly(ST-VS-B-E) at Room Temperature

Figure 2 displays the polymer poly(ST-VS-B-E) nanometer blocking material’s particle size distribution. The results in Figure 2 indicate that the particle size distribution of poly(ST-VS-B-E) was more concentrated and spike-shaped parabolic, with particle sizes ranging from 78.56 nm to 79.98 nm; the median particle size (D50) was 79.15 nm, and the particle size (D90) was 79.62 nm. The overall size of poly(ST-VS-B-E) was of nanometer level and could be used in nano-blocking.

3.1.3. Thermogravimetric Analysis

Temperature resistance is an important evaluation index of nanometer blocking materials. Figure 3 is the TG analysis diagram of poly(ST-VS-B-E). As can be seen from the TG-DTG curve in Figure 3, the TG curve decreases by 3.35% in the temperature range from 94 °C to 120 °C, which is due to the evaporation of water in the poly(ST-VS-B-E), so the TG curve decreases in this range. It can be seen from the curve that the temperature of the structural decomposition of poly(ST-VS-B-E) was 359.25 °C at the beginning, and the curve basically remained stable when the temperature was 416.75 °C. The mass loss from 359.25 °C to 416.45 °C was 73.40%. The thermal decomposition of poly(ST-VS-B-E) was basically completed. The results show that poly(ST-VS-B-E) has excellent thermal stability.

3.2. Evaluation of Water-Based Drilling Fluid Performance

We used the drilling fluid described in Section 2.3.1 for drilling fluid performance testing. Comparisons of water-based drilling fluid performance with different additions of poly(ST-VS-B-E) at 150 °C before and after aging for 16 h are shown in Figure 4, Figure 5, Figure 6 and Figure 7.

The results in Figure 4 indicate that before aging, when the amount of poly(ST-VS-B-E) did not exceed 1.5 wt%, the apparent viscosity and plastic viscosity of the drilling fluid gradually decreased with the increase in the amount of nano-plugging material poly(ST-VS-B-E). When the content of poly(ST-VS-B-E) was 1.5 wt%, the apparent viscosity decreased to 22.5 mPa·s and the plastic viscosity decreased to 18 mPa·s. When the dosage of poly(ST-VS-B-E) continued to increase to 2 wt%, the apparent viscosity and plastic viscosity of the drilling fluid increased to 35 mPa·s and 25 mPa·s, respectively. With the continuous increase in poly(ST-VS-B-E) dosage, the apparent viscosity and plastic viscosity of the drilling fluid showed a trend of first decreasing and then increasing, but the overall change was not obvious. After aging for 16 h at 150 °C, when the dosage of poly(ST-VS-B-E) did not exceed 1.5 wt%, the apparent viscosity and plastic viscosity of the drilling fluid increased slightly. When the dosage of poly(ST-VS-B-E) was 2 wt%, the apparent viscosity and plastic viscosity of the drilling fluid without plugging materials (26.5 mPa·s, 17 mPa·s) increased to 44.5 mPa·s and 24 mPa·s, respectively, with a significant increase. The reason is that poly(ST-VS-B-E) can form a continuous and dense spatial network structure in water after aging. With the increase in poly(ST-VS-B-E) concentration, the network structure became denser, and the width of the network skeleton was larger, thus increasing the viscosity of the drilling fluid. With the continuous increase in poly(ST-VS-B-E) dosage, the apparent viscosity of the drilling fluid increased slightly, and the plastic viscosity decreased slightly, but the degree of change was not obvious. The results in Figure 5 indicate that before aging, the dynamic shear of poly(ST-VS-B-E) was 17 Pa at 1 wt% addition, which is almost unchanged from the drilling fluid without blocking material (18 Pa). The larger decrease in dynamic shear force occurred at 1.5 wt%, 2 wt%, 2.5 wt%, and 3 wt% of poly(ST-VS-B-E) addition and fluctuated at lower values. After aging at 150 °C for 16 h, the dynamic shear force was substantially improved with the addition of poly(ST-VS-B-E) at 1 wt%, 1.5 wt%, 2 wt%, 2.5 wt%, and 3 wt%, and gradually increased with the increase in concentration. The reason is that after aging, the dense spatial mesh of poly(ST-VS-B-E) increased the viscosity of the drilling fluid, which in turn increased the dynamic shear of the drilling fluid. The results in Figure 6 indicate that before aging, the kinetic to plastic ratio of poly(ST-VS-B-E) was 0.71 at 1 wt% addition, which was almost unchanged from the drilling fluid without blocking material (0.58). The significant decrease in the yield point/plastic viscosity occurred at 1.5 wt%, 2 wt%, 2.5 wt%, and 3 wt% of poly(ST-VS-B-E) addition and fluctuated at lower values. After aging at 150 °C for 16 h, the yield point/plastic viscosity increased substantially with the increase of concentration when the addition of poly(ST-VS-B-E) was 1 wt%, 1.5 wt%, 2 wt%, 2.5 wt%, and 3 wt%. The reason for this is that after aging, the dynamic shear of the poly(ST-VS-B-E) drilling fluid increased dramatically, which enhanced the dynamic plastic ratio of the drilling fluid. The results in Figure 7 indicate that after aging for 16 h at 150 °C, the water loss at HTHP decreased from 8.4 mL to 6.8 mL and 6.7 mL, respectively, when the addition of poly(ST-VS-B-E) was 1 wt% and 1.5 wt% compared to the drilling fluid without blocking material (0 wt%), and there was a small decrease in water loss, but the change was not obvious. The water loss at HTHP decreased gradually with the increase in poly(ST-VS-B-E) when the dosage of poly(ST-VS-B-E) was 2 wt%, 2.5 wt%, and 3 wt%, and the water loss at HTHP was as low as 3.1 mL when the dosage was 2.5 wt% and 3.0 mL at 3 wt% as the dosage continued to increase, not a significant drop from the 2.5 wt% added drilling fluid. In general, with the increase of poly(ST-VS-B-E), the water loss at HTHP gradually decreased, and the rheological performance of drilling fluids was improved to a certain extent until the dosage of poly(ST-VS-B-E) was 2.5 wt%; the blocking effect was significantly improved, and the overall performance of the drilling fluid was excellent.

3.3. Evaluation of Blocking Performance

3.3.1. Sealing Performance Evaluation of a Simulated Mud Cake

The blocking effect evaluation of poly(ST-VS-B-E) at HTHP (150 °C, 3.5 MPa) was shown in Figure 8. The results in Figure 8 indicate that the permeability of a simulated mud cake without blocking materials was 1.17 × 10⁻³ mD, and the permeability reached 10⁻³ mD, which was used to simulate and evaluate the sealing performance of a shale formation. When the poly(ST-VS-B-E) content reached 2.5 wt%, the permeability decreased to 0.39 × 10⁻³ mD, and the blocking rate was 66.67%. With the increase in amount added, the blocking rate increased, but the change was not obvious. Therefore, the optimal amount for end-capping materials is 2.5 wt%. The end-capping material with this amount had excellent nano-blocking ability, combined with its sealing effect and economic benefits. Therefore, poly(ST-VS-B-E) can be used as an excellent nano-blocking additive in drilling fluid to prevent drilling fluid filtrate from entering nano-pore joints in shale formations, thus effectively avoiding the occurrence of reservoir damage.

3.3.2. Sealing Performance Evaluation of a Simulated Core

The blocking performance evaluation of poly(ST-VS-B-E) in a simulated core under HTHP (105 °C, 3.5 MPa) is shown in

Table 1. Evaluation of the sealing effect of poly(ST-VS-B-E) on simulated cores at 105 °C.

Name	Permeability after Blocking	Blocking Rate
	/10−3 mD	/wt%
Clearwater	5.85	-
2.5 wt% poly(ST-VS-B-E) + Clearwater	0.39	93.33

. It can be seen from Table 1 that when the optimal amount of poly(ST-VS-B-E) solution of 2.5 wt% was added to the permeability test device of SCLS-C4 tight core at HTHP, the sealing rate was up to 93.33%. The results showed that poly(ST-VS-B-E) had excellent blocking performance.

3.4. Simulation of the Microscopic Morphology of Mud Cake

The excellent blocking performance of poly(ST-VS-B-E) can be further proven by analyzing the micro-morphology of a simulated mud cake containing poly(ST-VS-B-E) nano-blocking material. Figure 9 and Figure 10 show the macroscopic and microscopic morphologies of the unsealed simulated mud cake and poly(ST-VS-B-E)-sealed simulated mud cake. The results in Figure 9a indicate that the surface of the simulated clay cake without poly(ST-VS-B-E) was rough and uneven. The results in Figure 9b indicate that the surface of the poly(ST-VS-B-E)-sealed simulated mud cake was smooth and even, and the density of the poly(ST-VS-B-E)-sealed simulated mud cake was significantly better than that of the unsealed simulated mud cake. The results in Figure 10a indicate that the unsealed mud cake electron microscope images show that there were a large number of micro- and nano-pores on the surface of the mud cake. These micro- and nano-pores are the main seepage channels through which drilling fluid filtrate intrudes into the borehole wall, which is the key to its instability. The results in Figure 10b indicate that after poly(ST-VS-B-E) blocking, the surface morphology of the mud cake was flat and compact, and poly(ST-VS-B-E) had a good blocking effect. Based on the macroscopic morphology and microstructure analysis, it was proven that poly(ST-VS-B-E) had excellent micro- and nano-blocking performance.

3.5. Research on the Nano-Blocking Mechanism of Poly(ST-VS-B-E)

The mechanism of poly(ST-VS-B-E) for micro- and nano-pore sealing in shale formations is shown in Figure 11. The results in Figure 11 indicate that the poly(ST-VS-B-E) is not only uniformly dispersed in the water-based drilling fluid but also has extremely strong adsorption when sealing the nanopore joints of shale because poly(ST-VS-B-E) has numerous sulfonic acid groups. When entering the micro- and nano-pores of shale, it can be adsorbed on the inner walls of the pores, and a dense film can be formed on the surface of the pores, which can effectively prevent the water-based drilling fluid filtrate from penetrating into the shale formation. Under the HTHP environment, poly(ST-VS-B-E) was able to enter the nanopore joints on the shale surface under pressure and continuously accumulate inside the pore joints to form bridging and an effective sealing structure, where a small amount of poly(ST-VS-B-E) passes through the nanopore joints on the shale surface to form further sealing at the internal pore joints.

4. Conclusions

(1)

Poly(ST-VS-B-E) was synthesized from styrene, vinyl sodium sulfonate, ethyl methacrylate, and butyl acrylate. The median particle size of the poly(ST-VS-B-E) nanometer blocking materials was 79.15 nm, which could resist a high temperature of 359.25 °C and had almost no effect on water-based drilling fluid performance. The apparent viscosity of the water-based drilling fluid with 2.5% poly(ST-VS-B-E) blocking material added was 48 mPa·s, the plastic viscosity was 21 mPa·s, the yield point was 27 Pa, and the fluid loss was 3.1 mL. With the increase in the amount of poly(ST-VS-B-E), the rock-carrying ability and blocking performance of the water-based drilling fluid were improved to a certain extent.

(2)

The plugging performance of water-based drilling fluid increased with the increase in poly(ST-VS-B-E) content. When the amount of poly(ST-VS-B-E) was 2.5 wt%, the blocking rate of the simulated mud cake could reach 66.67%. When the amount of poly(ST-VS-B-E) was 2.5 wt%, the blocking rate of the artificial core was up to 93.33%. The water-based drilling fluid with poly(ST-VS-B-E) nano-blocking material not only had stable performance, but also had excellent plugging performance in the simulated mud cake filtration test and the simulated core permeability test.

(3)

Poly(ST-VS-B-E), as a nano-blocking material, can accumulate at a certain distance from shale surface cracks under formation pressure and form a bridge to create an effective sealing structure. In addition, poly(ST-VS-B-E) has a strong adsorption effect. Poly(ST-VS-B-E) adsorbed on the inner wall of shale pore layers can effectively prevent water-based drilling fluid filtrate from infiltrating a shale formation. Poly(ST-VS-B-E) is expected to be a potential new nano-blocking material for shale formations with wellbore instability.