Based Drilling Fluids - Wiley Online Library

J Surfact Deterg (2018) 21: 155–164 DOI 10.1002/jsde.12019

ORIGINAL ARTICLE

Application of Nano-Polymer Emulsion for Inhibiting Shale Self-Imbibition in Water-Based Drilling Fluids Jian-gen Xu1 · Zhengsong Qiu1 · Xin Zhao1 · Yubin Zhang1 · Gongrang Li2 · Weian Huang1

Received: 4 September 2017 / Revised: 13 November 2017 / Accepted: 15 November 2017 © 2018 AOCS

Abstract In order to effectively solve shale instability problems in the drilling process, the remarkable capillary effect of shale formations cannot be ignored. In this paper, we report the development and characterization of a nanopolymer emulsion (SDPE) as a shale self-imbibition control agent in water-based drilling fluids. Spontaneous imbibition experiments, surface tension measurements, contact angle measurements, particle size distribution analysis, linear swelling tests, and hot-rolling cuttings dispersion tests were conducted to evaluate the comprehensive performance of SDPE. The results show that the water absorption of shale samples in SDPE emulsions is significantly less than in deionized water. At a concentration of 2.0%, the absorption mass decreased from 7.51 to 2.59%. Reducing the surface tension of the testing fluids, increasing the contact angle of the shale samples, and maintaining the nanoscale size were the important considerations for SDPE to greatly decrease the capillary effect. The low swelling rate and high recovery rate indicate that SDPE also exhibits strong shale hydration inhibition performance. Compared with waterbased drilling fluids without SDPE, drilling fluids with SDPE present higher yield point/plastic viscosity values, and also decrease the filtration loss. Based on our findings, SDPE has the potential to be a good shale self-imbibition

* Jian-gen Xu [email protected] Zhengsong Qiu [email protected] 1

School of Petroleum Engineering, China University of Petroleum (East China), Qingdao 266580, China

2

Drilling Technology Research Institute, Shengli Petroleum Engineering Corporation Limited of SINOPEC, Dongying 257017, China

Published online: 21 February 2018 J Surfact Deterg (2018) 21: 155–164

control agent and to help mitigate the shale instability problems. Keywords Nano-polymer emulsion Water-based drilling fluid Shale formation Spontaneous imbibition Shale hydration inhibition J Surfact Deterg (2018) 21: 155–164.

Introduction Wellbore instability is always a challenge in the drilling process (Hale, Mody, & Salisbury, 1993; Van Oort, Pasturel, Bryla, & Ditlevsen, 2017). Seventy-five percent of the strata encountered in the drilling process is composed of shale formations, and 90% of the borehole instability problems will appear in shale formations (Steiger & Leung, 1992; Xu, Qiu, Zhao, & Huang, 2017). Much effort has been made worldwide to solve the wellbore instability problems, but they still remain unsolved (Chen & Ewy, 2002; Liang, Chen, Jin, & Lu, 2014; Song et al., 2017). Especially, as a type of unconventional energy source, the development and utilization of shale gas has attracted much attention in recent years (Jarvie, Hill, Ruble, & Pollastro, 2007; Liu & Ostadhassan, 2017b; Zhou, Xue, Guo, & Li, 2016). But the development of shale gas in China is still at the exploratory stage and faces many problems, of which shale instability is one of the most serious ones (Ma & Chen, 2015; Zhou et al., 2016). Shales are fine-grained sedimentary rocks with low porosity and ultralow permeability. A large number of nanometersized pores and cracks develop in shale formations (Liu & Ostadhassan, 2017a; Yang, He, Yi, & Hu, 2016). Studies have shown that shales have a remarkable capillary effect, in

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addition to the mud filtrate invading into the shale formations under the drilling pressure differential (Singh, 2016; Wang, Chen, Jin, & Chen, 2016; Yang, Ge, et al., 2016). Spontaneous imbibition by the capillary effect can greatly promote the invasion of drilling fluids into the shale formations, thus leading to shale hydration (Dehghanpour, Lan, Saeed, Fei, & Qi, 2013; Gupta, Xu, Dehghanpour, & Bearinger, 2017; Zhang & Sheng, 2017). Shale hydration will further destroy the inner structure of shales and decrease the rocks strength, and eventually lead to borehole instability (Zhang, Sheng, & Shen, 2017; Zhong, Qiu, Huang, & Cao, 2012). However, past researches on wellbore stability have not paid enough attention to shale instability caused by the self-imbibition of shales. Therefore, from the perspective of decreasing the capillary effect, a kind of self-imbibition control agent needs to be developed to effectively prevent shale self-imbibition damage. Over the last few years, researchers have used microemulsions as a shale self-imbibition control agent (Bui, Akkutlu, Zelenev, & Silas, 2017; Qiu, Pang, Huang, Gao, & Liu, 2013). However, microemulsions have poor temperature resistance and are difficult to stabilize for long periods in drilling fluids (An, Jiang, Qi, Huang, & Shi, 2016; Tabibiazar et al., 2015). Therefore, the field application of microemulsions is greatly restricted. The need to find a feasible and effective method for inhibiting shale self-imbibition has become an urgent task. Currently, with the fast development of nanotechnology, the application of various nanomaterials in the oil and gas industry is garnering considerable attention (Abdo & Haneef, 2012; Jain, Mahto, & Sharma, 2015; Vryzas & Kelessidis, 2017; Zhang et al., 2015). Compared with microemulsions, nanopolymer emulsions (SDPE) have better high-temperature stability and can be uniformly dispersed in drilling fluids (Liu, Qiu, & Huang, 2015). Thus, SDPE has the potential to become a new approach to effectively inhibiting shale self-imbibition, thereby contributing to shale stability. We have prepared a novel SDPE to inhibit shale selfimbibition in water-based drilling fluids. SDPE can effectively decrease the capillary effect to improve shale stability. Table 1 Mineralogical composition of the shale samples Component

Content (wt%)

Component of clay mineral

Quartz Potassium feldspar Plagioclase Calcite

20 6

Kaolinite Chlorite

29 28

Iron dolomite Clay mineral

2 15

Illite Illite/smectite mixed layer – –

Content (wt%) 3 3 12 82 – –

Furthermore, SDPE can also help reduce the shale hydration potential and has good compatibility with water-based drilling fluids. To the best of our knowledge, this is the first time that a SDPE has been developed and used as a shale self-imbibition control agent in water-based drilling fluids.

Experimental Materials Butyl acrylate (BA), acrylic acid (AA), and styrene (St) were obtained from Chemicals (Shanghai, China). All monomers were used after vacuum distillation. Octylphenol ethoxylate (OP-10) and sodium dodecyl sulfate (SDS), used as emulsifiers, were purchased from Aladdin Reagents (Shanghai, China) and Sinopharm Chemicals. Potassium persulfate (KPS), which served as the initiator, was provided by Sinopharm Chemicals and used without further purification. Xanthan gum and low-viscosity polyanionic celluloses were provided by Shida Chuangxin Technology Co., Ltd. (Dongying, China). Potassium chloride was obtained from Sinopharm Chemicals. Sodium bentonite was purchased from Weifang Huawei Bentonite Group Co., Ltd. (Weifang, China), the mineralogical composition of which was reported by Zhong, Qiu, Huang, et al. (2015). Shale samples used in this work were siliceous shales obtained from the Turpan Hami Basin, China. The mineralogical composition of the shale samples were determined by X-ray diffraction (XRD) analysis and the results presented in Table 1. Preparation of SDPE The reactions were conducted in a 250-mL glass reactor equipped with a reflux condenser and a mechanical stirrer. The glass reactor was immersed in a thermostatted water bath whose the temperature was maintained at 75 C throughout the experiments. Under stirring conditions, St, BA, and AA with molar ratio of 6.0:3.5:0.5 were added into the reactor, wherein deionized water was used as the solvent. Then a certain amount of surfactants (SDS and OP-10) was added to the monomer solution to obtain the pre-emulsified liquid. After high-speed stirring for 1 h, the initiator (KPS) was added dropwise to the homogeneous emulsion to induce polymerization. After 3 h of reaction time, the SDPE was obtained. Characterization of SDPE The chemical structures of SDPE were characterized by Flourier transform infrared spectroscopy (FTIR, Nicolet J Surfact Deterg (2018) 21: 155–164

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6700, Madison, Wisconsin, USA), scanning from 4000 to 400 cm−1. The nuclear magnetic resonance spectrum was obtained with a 1H NMR spectrometer (Bruker AV500, Karlsruhe, Germany) using CDCl3 as the solvent. Spontaneous Imbibition Experiment The spontaneous imbibition experiment was conducted on an experimental device for core spontaneous imbibition. A schematic diagram of the experimental setup is shown in Fig. 1. The main experimental steps for this test were as follows. The shale samples were first dried in an oven at 105 C for 12 h. Then they were cooled to ambient temperature (maintained at 25 C) and their weight was recorded. The dried shale samples were then placed in the core holder, and the analytical balance was cleared. The test fluids were then added to a glass dish, ensuring that the bottom of the core was immersed in the test fluid. Finally, as the test fluid spontaneously got sucked into the shale sample, the weight change was recorded as a function of time. Surface Tension Measurement SDPE was diluted with deionized water at 25 C to obtain emulsion samples at different concentrations. After equilibrating for 4 h, the surface tension was measured by the platinum plate method using a BZY-1 surface tension instrument (Shanghai Geng Geng Instrument Company, Shanghai, China). Contact Angle Measurement The wettability of shale samples was measured by the static sessile drop method using a JC2000D5M contact angle tester (Zhongchen Company, Shanghai, China). The surface

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of the shale sample was first polished with sandpaper to remove the oxide film. Then the shale sample was placed in a beaker containing the prepared SDPE at different concentrations. After soaking for at least 6 h, the shale sample was air-dried at room temperature. Finally, a drop of water was placed on the shale surface and the contact angle was measured by image analysis. Particle Size Distribution Analysis The particle size distribution of SDPE was measured with dynamic light scattering using a NanoBrook Omni particle sizer (Brookhaven Instrument Corporation, New York City, New York State, USA). In this experiment, the prepared was diluted with distilled water to 1.0 g L−1 for particle size distribution measurement. The diluted emulsion (2.5 mL) was then poured into the sample cell, and the particle size distribution was measured three times. Linear Swelling Test The linear swelling test was used to evaluate the shale hydration inhibition performance of the shale inhibitors (Zhao et al., 2017). For the test, shale samples were pulverized to fine powders and sifted through a 100-mesh screen. After oven-drying at 105 C for 4 h, 10 g of the shale samples was compressed at 10 MPa pressure for 5 min to prepare the core sample. Then the core sample was placed in the NP-02A swelling instrument (Haitongda Company, Qingdao, China). After the core sample came into contact with test fluid, the expansion height of the core sample in the test fluid with time was recorded. Finally, the linear swelling rate of the shale was calculated by the ratio of the expansion height to the initial height of the core sample. Hot-Rolling Cuttings Dispersion Test This test was aimed at simulating the interaction between shale cuttings and the test fluid at certain temperatures (Zhong, Qiu, Sun, Zhang, & Huang, 2015). The dispersion characteristics of shale cuttings could reflect the shale inhibition effect of the test fluid. In brief, 50 g of shale cuttings with size 2.00–3.35 mm and 350 mL test fluid were added to the roller oven cell. After hot-rolling at 77 C for 16 h, the shale cuttings were screened with a 40-mesh sieve. They were then washed with fresh water and dried for 4 h at 105 C in a drying oven. Finally, the weight of the recovered shale cuttings was recorded to calculate the recovery rate. Compatibility Test

Fig. 1 Schematic diagram of shale spontaneous imbibition device

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Prehydrated sodium bentonite slurry was prepared by adding 16.0 g of sodium bentonite to 400 mL deionized water,

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stirred at 10,000 rpm for 20 min, and then prehydrated for 24 h at room temperature. The water-based drilling fluids were composed of the prehydrated sodium bentonite slurry, 0.8 g of xanthan gum, 4.0 g of low-viscosity polyanionic celluloses, and 12.0 g of potassium chloride. The mixture was stirred at a high speed (8000 rpm) for 20 min to obtain homogeneous dispersions. Then the dispersions were kept in an oven (Haitongda Company) and hot-rolled at 120 C for 16 h. After dynamic aging, the rheological properties and fluid loss of the water-based drilling fluids were measured. By comparing the rheological properties and fluid loss of the water-based drilling fluids with or without the addition of SDPE, the compatibility of SDPE with waterbased drilling fluids was investigated. In addition, in order to further study the performance of SDPE for inhibiting shale self-imbibition in water-based drilling fluids, the spontaneous imbibition amount of shales in the above-mentioned drilling fluids was measured. After the spontaneous imbibition experiments, the contact site between shale sample and the drilling fluids was characterized by scanning electron microscopy (SEM) analysis. Rheological properties, including apparent viscosity (AV), plastic viscosity (PV), and yield point (YP), were determined according to the API-recommended standard procedure using a ZNN-D6 rotating viscometer (Haitongda Company). The fluid loss (FLAPI) of the water-based drilling fluids was measured using a ZNS-2A filtration apparatus (Haitongda Company) at room temperature and 0.7 MPa for 30 min. The rheological parameters were calculated with the help of the following equations: Apparent viscosity ðAVÞ = Θ600 =2 ðmPa sÞ Plastic viscosity ðPVÞ = Θ600 − Θ300 ðmPa sÞ Yield point ðYPÞ = ðΘ300 − PVÞ=2 ðPaÞ

ð1Þ ð2Þ ð3Þ

where Θ600 is the viscometer reading at 600 rpm, and Θ300 is the reading at 300 rpm.

Results and Discussion Characterization of SDPE The FTIR spectrum of SDPE is shown in Fig. 2. The peaks at 3062, 3029, and 2925 cm−1 correspond to the C─H absorption peaks of the benzene ring. The peaks at 1599, 1494, and 1452 cm−1 are associated with the characteristic vibration of the benzene skeleton. Moreover, the peaks at 760 and 698 cm−1 are the characteristic peaks of the single substitution benzene ring, indicating that styrene successfully took part in the polymerization reaction. In addition, the stretching vibration peak of C═O was at 1731 cm−1, and the stretching vibration peak of C─O─C bond was 1161 cm−1, indicating that the product contained BA chain segments. Furthermore, the stretching vibration peak of ─OH bond was 3437 cm−1, and the stretching vibration peak of C═O was 1731 cm−1, indicating that AA chain segments existed in the product. No C═C absorption peak was observed within 1620–1680 cm−1, indicating that the polymerization was complete. The analysis was further confirmed by the nuclear magnetic resonance spectrum of SDPE, which is shown in Fig. 3. The chemical shifts of protons in the copolymer were determined in the 1H NMR spectrum, and the relevant positions were marked. It indicated that the three monomers were involved in the polymerization, and the chemical structure of SDPE was further confirmed. Therefore, through the FTIR and 1H NMR, the successful preparation of SDPE was confirmed. Spontaneous Imbibition Experiment

Fig. 2 FTIR spectrum of SDPE

The results of the shale spontaneous imbibition experiment are presented in Fig. 4. It can be concluded that the shale sample possessed strong spontaneous imbibition capacity in deionized water. At the initial stage, water absorption of shale samples increased rapidly after contacting with deionized water. After ~200 min, the water absorption tended to be stable, and the absorption mass of per gram of shale was 7.51%. Besides, it can be clearly seen that the water absorption of shale samples in SDPE solution is significantly less than in deionized water. After contact with 1.0 and 2.0% SDPE solution, the absorption mass of per gram of shale was only 4.40 and 2.59%, respectively. Compared to deionized water, the water absorption of the shale samples increased more slowly in the initial stage and reached a plateau more quickly. Therefore, it can be inferred that J Surfact Deterg (2018) 21: 155–164

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SDPE has excellent ability to inhibit shale self-imbibition. It can be regarded as an efficient self-imbibition control agent. Surface Tension Measurements The surface of shale is generally hydrophilic, and the capillary force is one of the driving forces for water-based drilling fluids to invade shale formations (Shen, Ge, Meng, Jiang, & Yang, 2017; Yang et al., 2017). Reducing the surface tension of the water-based drilling fluids is an effective way to decrease the capillary effect (Qiu et al., 2013). Thus, it can greatly reduce the invasion of drilling fluids into the shale formations and promote shale stability. Figure 5 shows the surface tension as a function of SDPE concentration. It can be seen that, with the increase of the SDPE concentration, the surface tension of the solutions decreased continuously. Especially at low concentrations, the surface tension decreased significantly. At a concentration of 0.1%, the surface tension was only 59.0 mN m−1, which was 1.21 times lower than that of deionized water. It can be seen that SDPE could effectively reduce the surface tension of the solutions. Contact Angle Measurements The wettability of the shale surface is also an important factor affecting the capillary force (Alvarez & Schechter, 2017). Increasing the contact angle of the shale surface is helpful in decreasing the capillary effect (Liang, Xiong, & Liu, 2015). The test results of contact angle are shown in Fig. 6. As shown in the figure, the contact angle for shale was ~34.4 , indicating that the shale sample possessed the hydrophilic property. After soaking with SDPE solutions, the contact angle increased. At a concentration of 0.2%, the

Fig. 4 Results of spontaneous imbibition tests for (a) deionized water, (b) 1% SDPE, and (c) 2% SDPE

contact angle increased to ~44.3 , which was 1.29 times more than that of shale itself. After that, with the increase of concentration, the contact angle continued to increase. The contact angle could reach as high as 82.1 with a concentration of 2.0%, nearing 90.0 . Thus, the wettability of shale surface was greatly changed after adsorption of SDPE, which became more hydrophobic to effectively decrease the capillary effect. Moreover, a more hydrophobic shale surface could significantly decrease the adsorption of water, thus favoring shale stability (Zhong et al., 2016). The capillary effect of shale samples can be quantitatively characterized by the capillary force using Eq. 4 (Qiu et al., 2013). Reducing the surface tension and increasing the contact angle can effectively reduce the capillary force. Geologically, shale is characterized by low porosity and ultralow permeability, and there are numerous micro-/nanoscale pore-throats developed in shale formations (Ewy & Morton, 2009; Sensoy, Chenevert, & Sharma, 2009). Assuming that the average pore-throat radius is 50 nm, the capillary force can be calculated according to the experimental data of Figs. 5 and 6 . The calculation results of the capillary force are shown in Fig. 7. pc = 2σ cos θ=r

Fig. 3 1H NMR spectrum of SDPE


ð4Þ

where pc is the capillary force (Pa), σ is the surface tension of the testing fluid (mN m−1), θ is the contact angle ( ), and r is the pore-throat radius of shale sample (mm). As shown in Fig. 7, it is obvious that SDPE could significantly reduce the capillary effect of the shale samples. When the shale samples came into contact with deionized water, the capillary force reached as high as 2.36 MPa, demonstrating a strong capillary effect. This further proves that the capillary effect of shale formations in the drilling process cannot be ignored. But, after the addition of SDPE, the capillary force was greatly decreased with increasing

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Fig. 5 Results of surface tension tests

concentration. With concentrations of 1.0 and 2.0%, the capillary force was decreased to 0.87 and 0.27 MPa, respectively, and the reduction rate of capillary force reached as high as 63.14 and 88.56%, respectively. This finding is in agreement with the test results of spontaneous imbibition tests presented in Fig. 4. Therefore, SDPE can be regarded as an efficient self-imbibition control agent. Reducing the surface tension of the testing fluids and increasing the contact angle of the shale samples are the important mechanisms for SDPE to greatly decrease the capillary effect of shale formations. Particle Size Distribution Analysis There are many polymer nanoparticles in the SDPE. The test results of the particle size distribution are shown in Fig. 8. As depicted in the figure, the nanoparticle size of SDPE is mainly distributed in the 30–135 nm with a

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Fig. 7 Calculation results of the capillary force with different concentrations

narrow particle size distribution. The D50 (median particle size) was 62 nm, while the D10 value was 44 nm and the D90 value was 88 nm. Based on previous reports (Liu et al., 2015; Xu, Qiu, Huang, & Zhao, 2017), it can be inferred that the polymer nanoparticles in this size range can bridge and seal the micro-/nano-scale pore-throats developed in shale formations. Finally, a dense plugging film can form on the shale surface, thus further reducing filtrate invasion. After the spontaneous imbibition experiments, the contact site between the shale sample and the testing fluid was characterized by SEM analysis. Figure 9 shows the results of the SEM analysis. Compared with deionized water, most of the micro-/nano-scale pores and cracks in the shale samples were plugged after contact with 2.0% SDPE. There is a dense plugging film formed on the shale surface, which was advantageous in reducing the self-imbibition capacity of the shale samples. This result confirmed our previous inference. Furthermore, the SDPE with nanoscale size can be another important mechanism to greatly decrease the capillary effect. Linear Swelling Test

Fig. 6 Results of contact angle tests

In order to investigate the shale hydration inhibition performance of SDPE, the linear swelling test at different concentrations was conducted. The results of the linear swelling test are shown in Fig. 10. It can be seen that the linear swelling rate of the shale sample in deionized water within 8 h was up to 12.93%, demonstrating a strong hydration swelling capacity. In comparison, after having conducted the linear swelling tests of 1.0% SDPE and 2.0% SDPE, the swelling rates were 6.80 and 4.67%, respectively, indicating that SDPE could effectively inhibit the hydration swelling of the shale sample. J Surfact Deterg (2018) 21: 155–164

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Fig. 8 Test results of the particle size distribution

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Fig. 10 Test results of the linear swelling test for (a) deionized water, (b) 1% SDPE, and (c) 2% SDPE

Hot-Rolling Cuttings Dispersion Test In order to further investigate the shale hydration inhibition performance of SDPE, the hot-rolling cuttings dispersion test at different concentrations was conducted. The results of the hot-rolling cuttings dispersion test are shown in Fig. 11. It can be seen that the recovery rate of the shale sample in deionized water was as low as 40.23%, demonstrating the strong hydration dispersion capacity. In comparison, after having conducted the hot-rolling cuttings dispersion tests at 1.0 and 2.0% SDPE, the recovery rates were 86.19 and 93.68%, respectively, indicating that SDPE could effectively inhibit the hydration dispersion of the shale sample. Similar to the results in the linear swelling tests, it can be concluded that SDPE could effectively inhibit the shale hydration, which is beneficial to the shale stability. The polymer nanoparticles with nano-scale size in the SDPE have a large specific surface area and a high surface energy, and therefore can be easily adsorbed onto the surface of the shale samples (Mao, Qiu, Shen, & Huang, 2015). Based on the results of the contact angle

measurement, after adsorption of SDPE, a more hydrophobic film was formed on the shale surface, and the adsorption of water was significantly decreased. The above can be the mechanisms for SDPE to effectively inhibit shale hydration. Compatibility Test Table 2 shows the effect of SDPE on the rheological properties in water-based drilling fluids. After hot-rolling at 120 C for 16 h, compared with the drilling fluids without SDPE, drilling fluids showed an increase in YP and a reduction in PV with the addition of 2.0% SDPE. Therefore, the drilling fluids with SDPE present higher YP/PV values, enhancing the shear-thinning property of the drilling fluids (Luo, Pei, Wang, Yu, & Chen, 2017). The cumulative filtrate volume of the drilling fluids based on the measuring time is presented in Fig. 12. The filtrate volume of the drilling fluids without SDPE was 8.2 mL, while that of drilling fluids with 2.0% SDPE decreased to

Fig. 9 SEM photos of shale samples: (a) after interact with deionized water, and (b) after interact with 2.0% SDPE


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Fig. 11 Test results of the hot-rolling cuttings dispersion test

6.8 mL, indicating that the filtration property of the waterbased drilling fluids with SDPE improved by 17.07%. The test results of shale spontaneous imbibition in waterbased drilling fluids are presented in Fig. 13. It can be concluded that the shale sample possessed weaker spontaneous imbibition capacity in water-based drilling fluids containing 2% SDPE. After contact with the water-based drilling fluids containing 2% SDPE, the absorption mass decreased from 7.04 to 2.34%. Therefore, it can be inferred that SDPE has excellent ability to inhibit shale self-imbibition in waterbased drilling fluids. After the spontaneous imbibition experiments, the contact site between the shale sample and the drilling fluids was characterized by SEM analysis. Figure 14 shows the test results of the SEM analysis. For water-based drilling fluids without SDPE, it could not form a dense plugging film, and the shale surface was very coarse. There are still many pores and cracks on the shale surface, as shown in Fig. 14a. But for the water-based drilling fluids containing 2.0% SDPE, a denser and smoother plugging film was observed, owing to the absorption of

Fig. 12 Cumulative filtrate volume against time at room temperature and 0.7 MPa for (a) the water-based drilling fluids, and (b) the waterbased drilling fluids containing 2% SDPE

SDPE on the shale surface, and most of the pores and cracks in the shale samples were plugged, as shown in Fig. 14b. Therefore, the shale sample showed lower spontaneous imbibition in the water-based drilling fluids containing 2.0% SDPE, indicating that SDPE possessed a strong capacity for decreasing the capillary effect in water-based drilling fluids. The newly prepared SDPE can be a potential shale self-imbibition control agent in water-based drilling fluids, thus helping to mitigate the shale instability problems.

Table 2 Effect of SDPE on the rheological properties in water-based drilling fluids after hot-rolling at 120 C for 16 h Parameter Θ at 600 rpm (lbf/100 ft2) Θ at 300 rpm (lbf/100 ft2) AV (mPa s) PV (mPa s) YP (Pa) YP/PV FLAPI (mL)

Before adding SDPE

After adding 2.0% SDPE

70

70

44

50

35 26 9 0.35 8.2

35 20 15 0.75 6.8

Fig. 13 Results of spontaneous imbibition tests for (a) the waterbased drilling fluids, and (b) the water-based drilling fluids containing 2% SDPE


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Fig. 14 SEM photos of shale samples: (a) after interact with the water-based drilling fluids, and (b) after interact with the water-based drilling fluids containing 2.0% SDPE

Conclusions

References

A SDPE as a shale self-imbibition control agent in waterbased drilling fluids was developed. The water absorption of shale samples in SDPE solution was significantly less than in deionized water. At a concentration of 2.0%, the absorption mass decreased from 7.51 to 2.59%. Reducing the surface tension of the testing fluids, increasing the contact angle of the shale samples, and possessing nanoscale size were the important mechanisms for SDPE to greatly decrease the capillary effect. A lower concentration of SDPE could significantly reduce the surface tension of the testing fluids, and the contact angle of shale samples could reach as high as 82.1 with a concentration of 2.0%. In addition, most of the micro-/nano-scale pores and cracks in the shale samples were plugged after contact with SDPE, and a dense plugging film could be formed on the shale surface. Furthermore, SDPE demonstrated strong shale hydration inhibition performance. The swelling rate decreased from 12.93 to 4.67%, and the shale recovery rate increased from 40.23 to 93.68% containing 2.0% SDPE. Meanwhile, the drilling fluids with SDPE presented higher YP/PV values, while the filtration loss could be slightly decreased. The shale samples showed lower spontaneous imbibition in the water-based drilling fluids containing 2.0% SDPE. Overall, it is concluded that SDPE will be a good shale self-imbibition control agent and help mitigate the shale instability problems. There are still some challenges that need to be further explored (e.g., the mechanism of SDPE along with extended rheological analysis) in order to take full advantage of such fluids. Studies is in progress that will address all these challenges.

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Acknowledgements This work was financially supported by the National Natural Science Foundation of China (No. U1562101), the National Science and Technology Major Project of China (Nos. 2016ZX05020-004, 2017ZX05032004-005 and 2016ZX05021-004), the Graduate Student Innovation Project from China University of Petroleum (East China) (No. YCX2017016), and China Postdoctoral Science Foundation (2017M612344).


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