Preparation and Application of New Polyhydroxy Ammonium Shale Hydration Inhibitor

Abstract

Wellbore instability caused by the hydration of shale formations during drilling is a major problem in drilling engineering. In this paper, the shale inhibition performance of polyhydroxy-alkanolamine was evaluated using an anti-swelling test, linear swelling test, wash-durable test and montmorillonite hydration and dispersion experiment. Additionally, the shale inhibition mechanism of polyhydroxy-alkanolamine was studied via Fourier transform infrared spectroscopy (FTIR), particle size, zeta potential, thermogravimetric analysis (TGA) and scanning electron microscopy (SEM). The results show that the use of polyhydroxy-alkanolamine (EGP-2) could result in a relatively lower linear swelling rate of montmorillonite, and the linear swelling rate of 0.3% EGP-2 is 26.98%, which is stronger than that of 4% KCl. The anti-swelling rate of 0.3% EGP-2 is 43.54%, and the shrinkage–swelling rate of 0.3% EGP-2 is 34.62%. The study on the inhibition mechanism revealed that EGP-2 can permeate and adsorb on the surface of montmorillonite. The rolling recovery rate of easily hydrated shale was as high as 79.36%, which greatly reduces the dispersion ability of water to easily hydrated shale. The results of this study can be used to maintain the stability of a wellbore, which is conducive to related research.

1. Introduction

Shale oil has been one of the outstanding technologies in the world in recent years [1]. In the process of oil field drilling, due to the hydration swelling of water-sensitive shale, drilling instability problems such as drilling scouring, pipe jamming, rock debris disintegration and bit ball often occur in shale formation [2,3]. According to the chemical characteristics of shale and drilling fluid, when water-sensitive shale (with a high montmorillonite content) is immersed in water-based drilling fluid, the shale may swell and disperse rapidly [4,5,6]. Therefore, many shale inhibitors have been widely used in water-based drilling fluids. Unfortunately, because of the environmental requirements, the use of most of shale inhibitors is limited. [7,8,9]. High-performance water-based drilling fluid adopts the basic idea of strengthening inhibition overall, relying on multiple treatment agents for synergistic suppression, and basically achieves the strong inhibitory effect of oil-based drilling fluid. In recent years, polyhydroxy-ammonium has received the extensive attention of researchers because of its more significant application effects in terms of inhibition, lubricity and stable rheology [10]. In addition, our research team has also conducted research in the field of drilling fluid treatment agents [11,12,13]. Therefore, we have proposed environmentally friendly alcohol amine inhibitors with multi-hydroxyl. Polyhydroxy-alkanolamine inhibitors can provide multiple adsorption sites on a montmorillonite surface and enhance the adsorption of inhibitors on the montmorillonite surface [14,15]. The binding of montmorillonite is mainly realized through hydrogen bonding, anchoring, electrostatic adsorption and hydrophobic action, which effectively inhibits the hydration, swelling and dispersion of montmorillonite [16,17,18]. At present, polyhydroxy-alkanolamines have excellent compatibility with traditional additives and can meet the requirements of environmental protection. They have been applied in many water-based-drilling fluids, and have very broad application prospects.

In this study, polyhydroxy-alkanolamine was used to permeate and adsorb on the surface of shale, thereby reducing the hydration of the montmorillonite minerals in shale formation and stabilizing the wellbore. In this paper, the shale inhibition performance of polyhydroxy-alkanolamine was evaluated via experimental methods, and its shale inhibition mechanism was comprehensively analyzed.

2. Experimental Materials and Methods

2.1. Materials and Reagents

Epoxy propanol and ethylenediamine were purchased from Xi’an Chemical Reagent Factory. Ethanol and acetone were purchased from the Shanghai Xinghuo chemical plant. Potassium chloride and sodium carbonate were purchased from the Tianjin Zhiyuan chemical reagent factory. Calcium-based montmorillonite and sodium-based montmorillonite were purchased from Xi’an Fengyun Chemical Co., Ltd. (Xi’an Fengyun Chemical Co., Ltd., Xi’an, China) Polyvinyl alcohol (PVA), guar gum (GG), CMC and modified starch (MS) were purchased from Yangzhou Runda Oilfield Chemical Co., Ltd. (Yangzhou Runda Oilfield Chemical Co., Ltd., Yangzhou, China)

2.2. Synthesis

A certain amount of ethylenediamine, epoxy propanol and solvents was placed in a round-bottom flask equipped with a reflux condenser and refluxed with magnetic stirring for 4 h. After cooling to room temperature, the solvent in the solution was evaporated to obtain the product. The reaction mechanism is shown in Figure 1. The names of synthetic inhibitors are shown in

Table 1. Nomenclature of inhibitors.

Reagent	Reagent	Solvent	Proportion	Nomenclature
Ethylenediamine	Epoxy propanol	Distilled water	1:1	EGD-1
			1:2	EGD-2
			1:3	EGD-3
		Ethanol	1:1	EGA-1
			1:2	EGA-2
			1:3	EGA-3
		Acetone	1:1	EGP-1
			1:2	EGP-2
			1:3	EGP-3

.

2.3. Optimization of Synthesis Conditions

The inhibition performance of synthetic products on montmorillonite is affected by the material ratio, concentration and medium of synthetic reaction. Therefore, the synthetic products with the best inhibition performance were preliminarily selected through inhibition performance parameters such as anti-swelling rate and linear swelling rate. In addition, the shale inhibition performance of polyhydroxy-alkanolamine was evaluated in water-based drilling fluid and its mechanism was studied. The relationship between the influencing factors can be better analyzed. Therefore, the L9 (3³) orthogonal experiment table was designed, and the linear swelling rate of montmorillonite after adding the inhibitor for 2 h was taken as the index of the hydration inhibition effect. The results are shown in

Table 2. Orthogonal experimental factors.

Factors	Solvent (A)	Ratio of Amine to Alcohol (B)	Concentration (C)
1	Distilled water	1:1	0.1%
2	Acetone	1:2	0.3%
3	Ethanol	1:3	1.0%

and

Table 3. Analysis of orthogonal experiment results.

Number	A	B	C
1	1	1	1
2	1	2	2
3	1	3	3
4	2	1	2
5	2	2	3
6	2	3	1
7	3	1	3
8	3	2	1
9	3	3	2

.

2.4. Anti-Swelling and Shrinkage–Swelling Evaluation

The industry-standard evaluation method for montmorillonite stabilizers of drilling fluid, SY/T 5971-2016 [19], was referred to for evaluating the influence of the inhibitor on the anti-swelling rate of montmorillonite. Inhibitor solutions of different concentrations were prepared. Montmorillonite (0.5× g) was weighed and put into a 10 mL centrifuge tube. A certain amount of the inhibitor solution was added into the centrifuge tube, and then fully stirred and shaken. After left to stand for 2 h, with a centrifuge at the speed of 1500 r/min for 15 min, the volume, V_a, was recorded. The inhibitor solution was replaced by water and kerosene, and the swelling volume of montmorillonite in water and kerosene was recorded as V_b and V₀, respectively. The calculation formula of the anti-swelling rate of montmorillonite is shown in (1):

$${\mathrm{B}}_1=\frac{V_b-V_a}{V_b-V_0}\times 100\%$$

(1)

where B₁ is the anti-swelling rate of montmorillonite; V_a is the swelling volume of montmorillonite in the inhibitor solution, in mL; V_b is the swelling volume of montmorillonite in water, in mL; V₀ is the swelling volume of montmorillonite in kerosene, in mL.

Montmorillonite (2× g) was added to the centrifuge tube. Kerosene (7 mL) was added to centrifuge tube No. 1, and distilled water was added to other centrifuge tubes. After being fully stirred and left to stand for 4 h, it was centrifuged for 15 min at the speed of 3000 r/min, and then the montmorillonite volume was recorded after centrifugation. The volume of montmorillonite in kerosene is V₀, and the volume of distilled water is recorded as V_W. After that, the supernatant in the centrifuge tube was poured out, and 7 mL inhibitor solutions of different concentrations were added, fully shaken, stirred and left to stand for 4 h before centrifugation. The montmorillonite volume was recorded as V_S. The calculation formula of the shrinkage–swelling rate of montmorillonite is shown in (2):

$${\mathrm{B}}_2=\frac{V_w-V_s}{V_w-V_0}\times 100\%$$

(2)

where B₂ is the shrinkage–swelling rate of montmorillonite; V_S is the swelling volume of montmorillonite in the inhibitor solution, in mL; V_w is the swelling volume of montmorillonite in water, in mL; V₀ is the swelling volume of montmorillonite in kerosene, in mL.

2.5. Wash-Durable Test

The evaluation of the water washing resistance of the montmorillonite inhibitor was based on the enterprise standard Q/SH 0053-2010 of China Petroleum and Chemical Corporation on technical requirements for montmorillonite stabilizers [20].

2.6. Montmorillonite Hydration and Dispersion Experiment

Inhibitor solutions of different concentrations were prepared at room temperature. Sodium-based montmorillonite (5 g) was added to the above solutions, shaken well and left to stand for 24 h. The swelling volume of montmorillonite in different solutions was recorded and the inhibition performance of the inhibitor was evaluated.

2.7. Linear Swelling

The industry-standard shale inhibitor evaluation method, SY/T 6335-1997 [21], for drilling fluid was referred to for evaluating the influence of the inhibitor on the linear swelling rate of montmorillonite. The calculation formula for the linear swelling rate of montmorillonite is shown in (3):

$$\mathrm{S}\mathrm{r}=\frac{Ro}{∆L}\times 100\%$$

(3)

where Sr is the linear swelling rate of montmorillonite; Ro represents the swelling of montmorillonite, in mm; $∆L$ is the core thickness, in mm.

2.8. Performance in Drilling Fluid

Briefly, the preparation of 4% calcium montmorillonite drilling fluid was as follows. Calcium montmorillonite (14 g) and sodium carbonate (0.7 g) were added to tap water (350 mL), stirred at a high speed for 2 h and aged at 298 K for 24 h for use [22]. The preparation of treatment mud went as follows. The drilling fluid and treatment agent were aged for 6 h, stirred at a high speed for 10 min and tested for their performance [23]. The rheological properties, filtration properties and lubrication properties of the drilling fluid, such as AV (apparent viscosity), PV (plastic viscosity), YP (yield point), FL (API filtration) and tg (friction coefficient), were determined. A viscometer (ZNN-D6S, Hetongda Co., Ltd. Qingdao, China), medium pressure filtration instrument (GJSS-B12K, Haitongda Co., Ltd. Qingdao, China) and viscosity coefficient instrument (Qingdao Hetongda Co., Ltd. Qingdao, China) were adopted in accordance with the formulas in Chinese National Standard GB/T 16783.1-2006 [24].

2.9. Shale Rolling Recovery Experiment

The shale was crushed, and 6–10 mesh shale pieces were screened out for use in the experiments. Before the experiments, the shale pieces were dried at 100 ± 2 °C for 2 h. An amount of 50 g of shale pieces (6–10 mesh) was weighted and added to 350 mL of the inhibition solution, transferred into a stainless-steel aging cell and aged at 120 °C for 16 h. After aging, a 40-mesh standard sieve was used to filter the shale pieces, and the material left on the sieve was dried at 105 °C and weighed (M₁). Equation (4) was used to calculate the shale recovery rate.

$$\mathrm{S}\mathrm{h}\mathrm{a}\mathrm{l}\mathrm{e}\mathrm{r}\mathrm{e}\mathrm{c}\mathrm{o}\mathrm{v}\mathrm{e}\mathrm{r}\mathrm{y}=\frac{M_1}{50}\times 100\%$$

(4)

where M₁ is the mass of the recovered shale pieces after drying (g).

2.10. FT-IR Analysis

The dried inhibitor samples were ground. During the test, the ground samples were mixed with KBr at a ratio of 1:100, put into the tablet press and pressed into transparent flakes. Additionally, the soil samples were scanned and analyzed using an infrared spectrometer [25].

2.11. Particle Distribution Measurement

The dried inhibitor samples were used to measure particle sizes using a laser particle size experiment, so as to obtain the median particle size and average particle size of the montmorillonite particles in mud treated with the treatment agent. The change in montmorillonite particle size was analyzed according to these data [26].

2.12. Zeta Potential Measurement

The zeta potential of the supernatant of the solution was measured via the omni multiangle particle size and using a high-sensitivity zeta potential analyzer. The changes in the zeta potential of graphite with different dosages of adsorbent were analyzed [27].

2.13. SEM and TGA

The montmorillonite samples were dispersed in the inhibitor solution and hydrated for 24 h, and then the water was separated from it and dried at 105 °C for TGA and SEM. The TGA experiment was conducted on a TGA/DSC thermal analysis instrument (1/1600, METTLER TOLEDO, Inc., Columbus, OH, USA) at a ramp of 20 °C/min from room temperature to 825 °C under a nitrogen flow. The surface morphology of the montmorillonite samples was evaluated using a digital microscope imaging scanning electron microscope (model SU6000, serial NO. HI-2102-0003) at a 40.0 kV accelerating voltage on the basis of the reported method [28,29].

3. Results and Discussion

3.1. Screening of Synthesis Conditions

The orthogonal test results of the influence of the inhibitors synthesized by using ethylenediamine and epoxy propanol in different solvents on montmorillonite swelling are shown in

Table 4. Orthogonal test results.

Number	Swelling Rate/%	Number	Swelling Rate/%
1	48.41	6	46.61
2	35.25	7	50.61
3	48.93	8	42.13
4	35.70	9	47.08
5	29.75

, the experiment results of range analysis are shown in

Table 5. Analysis of experimental results obtained via range method.

Project	A	B	C
K1	44.20	44.91	40.10
K2	37.35	41.33	39.34
K3	46.61	41.92	48.72
Range	9.25	3.58	9.37
Patch	2	3	1

and the main effect diagram of the mean value from the orthogonal experiment is shown in Figure 2.

It can be seen from Table 4 and Table 5 and Figure 2 that the inhibitor synthesized via ethylenediamine and epoxy propanol has the most significant inhibition effect on montmorillonite; ethylenediamine and epoxy propanol react in a molar ratio of alcohol to amine functional groups of 1:2, the solvent is acetone, and the inhibitor dosage is 1.0%. As a consequence, the amount of inhibitor is the main factor affecting the linear swelling rate of montmorillonite, followed by the reaction medium, and the molar ratio of ethylenediamine to epoxy propanol, which has the least effect.

3.2. Anti-Swelling and Shrinkage–Swelling

The effects of inhibitors on the anti-swelling rate and shrinkage–swelling rate of montmorillonite were evaluated. The results are shown in

Table 6. Anti-swelling rate and shrinkage–swelling rate of montmorillonite synthesized via different solvents in the same proportion and concentration.

Inhibitors	Anti-Swelling Rate/%	Shrinkage–Swelling Rate/%
0.3% EGD-2	36.78	34.62
0.3% EGA-2	24.56	18.50
0.3% EGP-2	43.54	34.62

and

Table 7. Anti-swelling rate and shrinkage–swelling rate of montmorillonite synthesized in different proportions in the same solvents and concentrations.

0.3% EGP	Anti-Swelling Rate/%	Shrinkage–Swelling Rate/%
EGP-1	26.32	11.54
EGP-2	43.54	34.62
EGP-3	28.78	16.78

and Figure 3. It can be seen from Table 6 that when the synthetic molar ratio is 1:2 and the concentration is 0.3%, the synthetic products in different solvents have different effects on the anti-swelling rate and shrinkage–swelling rate of montmorillonite. The anti-swelling rate of 0.3% EGP-2 is 43.54%, and the shrinkage–swelling rate is 34.62%. The anti-swelling rate of 0.3% EGA-2 is 24.56%, and the shrinkage–swelling rate is 18.50%. This shows that the same concentration and the same molar ratio also have a certain impact on the inhibition performance of the corresponding products when changing the solvent. When the solvent is acetone, the anti-swelling rate and shrinkage–swelling rate of the product are relatively high, and the inhibition performance of clay is the most significant.

The effects of EGP synthesized in acetone solvent with different molar ratios on the anti-swelling rate and shrinkage–swelling rate of montmorillonite are shown in Table 7. It can be seen from Table 7 that EGP-2 has the greatest impact on the anti-swelling rate and shrinkage–swelling rate of montmorillonite when the concentration is the same and the synthetic molar ratio is 1:2. The anti-swelling rate of EGP-2 is 43.54%, which is 39.55% of that of EGP-1. The shrinkage–swelling rate of EGP-2 is 34.62%, which is 66.67% of that of EGP-1. The results show that when the concentration and solvent are the same and the ratio is 1:2, the inhibitor has the most significant inhibition effect on montmorillonite.

The influence of the EGP-2 concentration on the montmorillonite anti-swelling rate and shrinkage–swelling rate is evaluated as shown in Figure 3. It can be seen from Figure 3 that with the increase in concentration, the anti-swelling rate and shrinkage–swelling rate increase first and then decrease. When the concentration of EGP-2 is 0.3%, the anti-swelling rate and shrinkage–swelling rate are the highest, at 43.54% and 34.62%, respectively. After that, the concentration continues to rise, and the anti-swelling rate and shrinkage–swelling rate begins to decrease slowly. The reason may be that the concentration of EGP-2 is too high, which causes flocculation with montmorillonite and affects its inhibition performance.

3.3. Wash-Durable Test

EGP inhibition performance can be evaluated through the wash-durable rate experiment. The volume change of montmorillonite immersed in different solutions can be measured quantitatively and regularly via centrifugation, as shown in

Table 8. Results of wash-durable rate experiment (25 °C).

Solution	Swelling Volume/mL	Swelling Volume after Water Washing/mL	Wash-Durable/%
Distilled water	8.5	\	\
4.0% KCl	5.5	8.7	63.22
0.1% EGP-2	6.2	8.7	71.26
0.3% EGP-2	7.0	8.8	79.55
1.0% EGP-2	6.5	8.5	76.47

. It can be seen from Table 8 that after the montmorillonite was added to the EGP aqueous solution, the swelling volume decreased significantly. The wash-durable rate of the 0.3% EGP-2 aqueous solution is 79.55%, which is 20.53% of that of 4.0%KCl and 10.42% of that of 0.1% EGP-2. The results show that EGP-2 can be more firmly adsorbed on the surface of montmorillonite. Therefore, the inhibition performance of EGP-2 was further evaluated.

3.4. Montmorillonite Hydration and Dispersion

Through the montmorillonite hydration experiment, the inhibition performance of EGP-2 on montmorillonite was evaluated. Sodium-based montmorillonite (5 g) was added to EGP-2 solutions of different concentrations, shaken and left to stand for 24 h. It was then then observed and the findings recorded. Figure 4 shows the experimental results after it was left to stand for 24 h, with clean water as the comparison. It can be seen from Figure 4 that the swelling volume of montmorillonite with EGP-2 added is significantly lower than that of montmorillonite in clean water. Additionally, the swelling volume of montmorillonite decreases with the increase in concentration. This shows that the higher the concentration is, the stronger the inhibition of EGP-2 on montmorillonite is, which effectively inhibits the hydration and dispersion of montmorillonite. However, the inhibitor needs to act in the drilling working fluid together with other treatment agents. It is easy for an excessive concentration to cause flocculation and affect other properties of the working fluid. Therefore, we will continue to evaluate the compatibility of the inhibitor and drilling fluid in a later stage.

3.5. Linear Swelling

During the drilling process, wellbore collapse and instability have a very bad irreversible impact on the exploitation of the oilfield [30]. The linear swelling rate measured in laboratory experiments can reflect the instability degree of shaft wall collapse to a certain extent. Therefore, the effect of EGP-2 on the linear swelling of montmorillonite was evaluated via the montmorillonite tablet pressing method. The results are shown in Figure 5. It can be seen from Figure 5 that montmorillonite is rapidly hydrated and expanded within 20 min, and the linear swelling rate increases rapidly. After 40 min, the growth rate tends to slow down. After 120 min, the growth rate reaches a relatively stable state. At this time, the linear swelling rates of 0.2% and 0.3% EGP-2 are low, at 35.71% and 26.98%, which are 42.69% and 56.70% of those with clean water. Additionally, these values are 22.10% and 41.14% of the swelling rate of 4.0% KCl, and lead to strong inhibition performance. The reason for this phenomenon may be that EGP-2 has a large adsorption energy, which can replace the water molecules adsorbed on the surface of montmorillonite and destroy the orderly arranged water molecule structure layer between the surface and layers of the soil sample. Thus, it plays a crucial role in inhibiting the hydration and dispersion of montmorillonite. Furthermore, in the actual operation process, it is beneficial to stabilize the borehole wall. At the same time, the bit mud pack phenomenon is reduced and oil recovery is improved.

3.6. Performance in Drilling Fluid

At room temperature, 0.1%, 0.3% and 1.0% EGP-2 were added to the drilling fluid. The effect of different concentrations of EGP-2 on the performance of water-based drilling fluid was evaluated. It can be seen from

Table 9. Effect of EGP-2 concentration on drilling fluid performance.

Additive	AV/(mPa·s)	PV/(mPa·s)	YP/Pa	YP/PV Pa/(mPa·s)	FL/mL	tg
Mud	2.00	1.4	0.60	0.43	15.9	0.0437
Mud + 0.1% EGP-2	3.75	1.5	2.25	1.50	18.0	0.1051
Mud + 0.3% EGP-2	4.00	3.0	1.00	0.33	13.0	0.1139
Mud + 1.0% EGP-2	3.75	1.5	2.25	1.50	16.9	0.1317

that the apparent viscosity (AV), dynamic shear force (YP), plastic viscosity (PV) and sliding block resistance coefficient (tg) of the drilling fluid increased to a certain extent after the inhibitors at different concentrations were added. When the concentration was 0.3%, the filtration loss (FL) was the lowest, at 13.0 mL. It is compared with that of the drilling fluid, in which the AV is increased by 2.0 times, the YP is increased by 2.1 times and the PV is increased by 1.7 times. However, the filtration rate was reduced to a certain extent, to 18.2%, which shows that the filtration rate was effectively controlled. In addition, when the EGP-2 concentration was 0.1%, the FL increased to 13.21% of that of the drilling fluid. When the concentration was 1.0%, the filtration rate0 increased to 6.29% of that of the drilling fluid. The results show that there was no filtration reduction, the filtration rate was too high, the mud cake was too thick and the solid content in the drilling fluid was reduced, which affected the drilling speed.

At room temperature, 0.3% EGP-2 was added to CMC-, PVA-, MS- and GG-treated mud. It can be seen from

Table 10. Effect of 0.3% EGP-2 on performance of different drilling fluids.

Additive	AV /(mPa·s)	PV /(mPa·s)	YP /Pa	YP/PV Pa/(mPa·s)	FL/mL	tg
Mud	2.00	1.4	0.60	0.43	15.9	0.0437
0.5% CMC	10.00	9.0	1.00	0.11	4.8	0.0875
0.5% CMC + 0.3% EGP-2	18.50	11.5	7.00	0.61	5.9	0.1763
1.0% PVA	7.00	7.00	0.00	0.00	4.6	0.1944
1.0% PVA + 0.3% EGP-2	11.75	9.0	2.75	0.23	7.4	0.1944
1.0% MS	6.90	6.0	0.90	0.15	10.8	0.1405
1.0% MS + 0.3% EGP-2	7.00	4.5	2.50	0.56	5.8	0.1853
0.3% GG	16.00	9.0	7.00	0.44	16.0	0.0437
0.3% GG + 0.3% EGP-2	17.50	11.0	6.50	0.37	14.0	0.0524

that the performance parameters of drilling fluid increased after the treatment agents were added. After 0.3% EGP-2 was added to the CMC treated mud, the AV increased by 45.95%, the YP increased by 21.74%, the PV increased by seven times, and the FL and the tg were also increased to a certain extent. Then, the flowability parameters of the PVA-treated mud changed greatly after the inhibitor was added to the PVA treated mud. The AV, PV and YP all increased. The AV increased, which strengthened the suspension capacity. However, the tg showed no change and had no effect on the lubricity of the drilling fluid. In addition, the MS treatment agent could effectively control the filtration of the drilling fluid and adjust the rheology of the drilling fluid, with a significant anti-sloughing effect. Therefore, after 0.3% EGP-2 was added to the MS-treated mud, the FL was further effectively controlled and reduced from 10.8 mL to 5.8 mL. The AV, YP and YP/PV were 1.01, 2.78 and 3.73 times those of MS, respectively. At the same time, GG had increased viscosity in the water-based drilling fluid and a certain filtration reduction property. Therefore, after 0.3% EGP-2 was added to GG-treated mud, the AV and PV were 1.09 and 1.22 times those of of GG-treated mud, respectively. However, the filtration rate and the tg were basically unchanged. In other words, a certain amount of EGP-2 being added to CMC-, PVA-, MS- and GG-treated mud can effectively improve the rheological properties of various drilling fluids. Briefly, 0.3% EGP-2 has good compatibility with CMC, PVA, MS and GG, but it has the best compatibility with MS.

3.7. Shale Rolling Recovery

Organic amine inhibitors are relatively expensive, and the amount added to the drilling fluid during the drilling process generally does not exceed 1%. Taking into account the actual addition of various shale inhibitors to the drilling fluid, shale recovery tests were conducted to evaluate the inhibitory performances of tap water, 7% KCl, 0.3% NW-1 (a low molecular weight quaternary ammonium salt shale inhibitor) and 0.3% EGP-2 on easily hydrated shale. The experiment results are shown in Figure 6. It can be seen from Figure 6 that the shale recovery rate of tap water is 9.52%, indicating that shale samples are very easy to hydrate, and that hydration dispersion is serious. KCl is a common inorganic salt shale inhibitor. The recovery rate of shale is 18.56%, indicating that 7% KCl solution can basically not inhibit the hydration and dispersion of shale formation. However, low-molecular quaternary ammonium salt is a new shale inhibitor. Because of its excellent inhibition properties, it has been used more and more in drilling fluids. The low-molecular quaternary ammonium salt shale inhibitor NW-1 was used in this paper. The shale recovery rate of 0.3% NW-1 is 61.23%, indicating that the quaternary ammonium salt shale inhibitor has a certain effect on shale. The shale recovery rate of 0.3% EGP-2 is 79.36%, which is higher than that of NW-1 with the same concentration. EGP-2 contains a large number of adsorbed hydroxyl functional groups which can be firmly adsorbed on the shale surface through hydrogen bonding and electrostatic interaction. The shale diffusion electric double layer was compressed, so as to replace the water between shale layers.

3.8. FTIR Analysis

The montmorillonite particle samples were analyzed by pressing infrared spectrum, as shown in Figure 7. It can be seen from Figure 7 that the montmorillonite treated with 0.3% EGP-2 has vibration peaks at 3620 cm⁻¹ and 3422 cm⁻¹, which can be attributed to the characteristic peak of -OH. And the characteristic peak near 1034 cm⁻¹ and 798 cm⁻¹ are the anti-stretching vibration of Si-O-Si. However, it is compared with the montmorillonite, the FTIR spectra of the treated montmorillonite shows no obvious change. The reason may be that some -OH and Si-O-Si on the montmorillonite are masked by EGP-2, which has no obvious effect on the lattice structure of the montmorillonite.

3.9. Particle Distribution

The inhibitor has a certain microscopic effect on the particle size of montmorillonite. The influence of synthetic products on the particle size of montmorillonite particles was analyzed by laser particle size analysis of un-treated montmorillonite particles and montmorillonite particles treated with different solutions [31]. It can be seen from

Table 11. Average particle size and median particle size of sodium-based montmorillonite in 0.3% EGP-2 solution.

Treatment of Montmorillonite	The Average Particle Size/μm	Median Particle Size/μm
Un-treated	14.270	11.020
Water treated	7.903	4.660
0.3% EGP-2 un-treated	8.132	7.098
0.3% EGP-2 treated	12.832	10.779

and Figure 8 that the average particle size and median particle size of un-hydrated montmorillonite are 14.270 μm and 11.020 μm, respectively. The average particle size and median particle size of fully hydrated montmorillonite in clean water are 7.903 μm and 4.660 μm, respectively. In addition, after 0.3% EGP-2 was added, the average un-hydrated particle size was reduced to 43.01% of the original particle size, and the median particle size was reduced to 35.59% of the original median particle size. The average particle size and median particle size were increased after hydration, and were 1.62 times and 2.31 times those of the original hydration group, respectively.

3.10. Zeta Potential

The hydration swelling and dispersion of montmorillonite are caused by many factors. These factors depend not only on the composition and structure of montmorillonite, but also on the composition of exchangeable cations and the properties of the dispersion medium. The value of the zeta potential of the dispersing medium solution is closely related to that of the dispersing state of montmorillonite. The smaller the montmorillonite particle size is, the greater the absolute value of zeta potential is, and the montmorillonite particles in the system are more dispersed and stable. That is, the dispersion force is greater than the cohesion [32,33]. On the contrary, the smaller the absolute value of the zeta potential is, the more it tends to agglomerate and shrink. That is, the attraction is strong to disperse the force, which makes it easy for particles to agglomerate and gather together. The relationship between zeta potential on the surface of montmorillonite particles and EGP-2 solution concentration is shown in Figure 8. Due to the lattice substitution phenomenon, an excess negative charge is generated in the crystal structure of montmorillonite minerals, so montmorillonite particles show a negative charge. It can be seen from Figure 9, the zeta potential on the surface of montmorillonite particles in clean water is −21.41 mv. This shows that montmorillonite particles have significant dispersibility in clean water. In Figure 9, with the increase in the EGP concentration in clean water, the zeta potential of the solution decreased, and the system reached a new stable equilibrium state of agglomeration dispersion. This shows that EGP can effectively inhibit the hydration and dispersion of montmorillonite.

3.11. SEM

SEM was used to analyze the micromorphology of montmorillonite particles treated and dried with 0.3% EGP-2 and clean water to evaluate the effect of EGP-2 on the microstructure of montmorillonite. The results are shown in Figure 10. Figure 10a shows the SEM microstructure of un-hydrated montmorillonite. (b) and (c) are the SEM microstructures of montmorillonite after hydration treatment in clean water and in 0.3% EGP-2 solution for 24 h and after drying. It can be seen from Figure 9 that montmorillonite was strongly dispersed in clean water, and the fine particles of montmorillonite were significantly reduced after 0.3% EGP-2 was added. This indicates that after 0.3% EGP-2 was added, the inhibitor entered the montmorillonite interlayer. The montmorillonite layers are combined via electrostatic adsorption and hydrogen bonding to effectively inhibit the hydration swelling and dispersion of montmorillonite. This phenomenon shows that it has a significant inhibitory effect on montmorillonite [34].

3.12. TGA

Montmorillonite contains a lot of water. With an increase in temperature, the adsorbed water, interlayer water and hydroxyl water in montmorillonite are removed in turn [35,36]. Therefore, TGA can be used to determine the weight loss rate of montmorillonite treated with different inhibitors, so as to evaluate the effect of inhibitors on the water absorption, hydration swelling and dispersion of montmorillonite. After the montmorillonite was soaked in clean water and 0.3% EGP-2 solution for 24 h, it was dried at 105 °C for TGA. It can be seen from Figure 11 that as the temperature gradually increases, the water between montmorillonite layers begins to evaporate and the weight of montmorillonite particles begins to decrease. Apparently, when the temperature rises from 50 °C to 350 °C, the weight loss rate of montmorillonite treated in clean water is 4.10%, and that of montmorillonite treated in EGP-2 solution is 1.46%. The weight loss rate of the sample soaked in EGP-2 solution was significantly lower than that of the sample soaked in clean water. This indicates that EGP-2 can obviously prevent the penetration of water molecules into shale, and has a certain inhibitory effect on the hydration swelling and dispersion of montmorillonite. The characteristics of macroscopic performance are that the weight loss rate of montmorillonite decreases and the water absorption is small.

3.13. Mechanism

The mechanism of inhibiting hydration and of the swelling of polyhydroxy-alkanolamine inhibitors in montmorillonite was systematically discussed, based on diffusion double layer theory. It is generally believed that the core purpose of inhibitors is to reduce the repulsion between montmorillonite crystal layers and prevent contact between water and montmorillonite particles [37,38,39]. As shown in Figure 12, EGP-2 has a polyhydroxy structure, which can provide multiple adsorption points on the surface of montmorillonite, and can be well embedded between montmorillonite layers. Additionally, the closely bound montmorillonite layers can reduce the trend of water molecules entering the montmorillonite layers. The inhibitor is adsorbed on the montmorillonite surface to neutralize the negative charge of montmorillonite, or attached to the crystalline layer of the montmorillonite to reduce the charge between the crystalline layer and the surface [40,41,42]. At the same time, it can combine montmorillonite through electrostatic adsorption, hydrogen bonding, anchoring and hydrophobic interaction, and effectively inhibit the hydration, swelling and dispersion of montmorillonite. Secondly, the adsorption between the dissociated primary amine group of EGP-2 and the crystalline layer of active montmorillonite pulls together the upper and lower crystalline layers of montmorillonite [43,44] to prevent the swelling of the crystalline layer caused by hydration, so as to obtain strong shale inhibition performance.

4. Conclusions

In this study, a polyhydroxy-alkanolamine inhibitor was synthesized from ethylenediamine and epoxy propanol. The inhibition performance of 0.3% EGP-2 was studied in detail. The results show that 0.3% EGP-2 has obvious hydration inhibition performance. Firstly, the linear swelling rate of 0.3% EGP-2 is only 26.98%, which is 56.70% and 41.14% lower than that of tap water and 4% KCl, respectively. The inhibition mechanism was also studied via FTIR, particle size analysis, SEM and TGA. The synthesized inhibitor has a polyhydroxy structure, which can provide multiple adsorption sites on the montmorillonite surface, and enhance the adsorption of the inhibitor to montmorillonite. In addition, the inhibitor is adsorbed on the montmorillonite surface and the montmorillonite is negatively charged or attached to the montmorillonite crystal layer to reduce the charge between the crystal layer and the surface. At the same time, the binding of montmorillonite is realized through electrostatic adsorption, hydrogen bonding, anchoring and hydrophobic action, which can effectively inhibit the hydration, swelling and dispersion of montmorillonite and reduce wellbore instability caused by shale hydration. Therefore, the polyhydroxy-alkanolamine inhibitor has obvious an inhibition property in montmorillonite.