TY - JOUR
AU - Yi,, Ding
AB - Abstract With increasing demand for energy and advances in exploration and development technologies, more attention is being devoted to exploration and development of deep oil and gas reservoirs. The Nanpu Sag contains huge reserves in deep oil and gas reservoirs and is a promising area. In this paper, the physico-chemical and mechanical properties of hard brittle shales from the Shahejie Formation in the Nanpu Sag in the Bohai Bay Basin of northern China were investigated using a variety of methods, including x-ray diffraction analysis, cation exchange capacity (CEC) analysis, contact angle measurements, scanning electron microscope observations, immersion experiments, ultrasonic testing and mechanical testing. The effects of the physico-chemical properties of the shales on wellbore instability were observed, and the effects of hydration of the shales on wellbore instability were also examined. The results show that the major mineral constituents of the investigated shales are quartz and clay minerals. The clay mineral contents range from 25.33% to 52.03%, and the quartz contents range from 20.03% to 46.45%. The clay minerals do not include montmorillonite, but large amounts of mixed-layer illite/smectite were observed. The CEC values of the shales range from 90 to 210 mmol kg-1, indicating that the shales are partly hydrated. The wettability of the shales is strongly water-wetted, indicating that water would enter the shales due to the capillary effect. Hydration of hard brittle shales can generate cracks, leading to changes in microstructure and increases in the acoustic value, which could generate damage in the shales and reduce their strength. With increasing hydration time, the shale hydration effect gradually becomes stronger, causing an increase in the range of the acoustic travel time and decreases in the ranges of cohesion and internal friction angles. For the hard brittle shales of the Nanpu Sag, drilling fluid systems should aim to enhance sealing ability, decrease drilling fluid filter loss and increase the amount of clay-hydration inhibitor used. Nanpu Sag, Shahejie Formation, hard brittle shale, physico-chemical properties, mechanical properties 1. Introduction With increasing demand for energy from oil and gas and large-scale development of conventional oil and gas reservoirs at middle or shallow depths, exploration for oil and gas resources is becoming increasingly difficult. Resources at depths of over 4500 m are a key area for oil and gas exploration (Dyman et al2002, Pang et al2015). Exploration for deep oil and gas reservoirs began in the United States in the 1950s. At present, more than 70 countries have carried out exploration for deep oil and gas resources, and there have been numerous technical breakthroughs in terms of well drilling and completion, which has resulted in many major accomplishments in deep oil and gas exploration and development (Jemison 1979, Law and Clayton 1987, Perry 1997, Sun et al2013, Bai and Cao 2014). The Bohai Bay Basin in northern China is a major oil and gas producing area and has seen almost 40 years of exploration and development. In the meantime, the resource in deep formations is approximately 35% of the total resource in the Bohai Bay. The Nanpu Sag is the richest area for deep oil and gas exploration (Wang et al2002, Dong et al2010). Recently, many of the deep wells and the extended reach wells in the Nanpu oilfield were increased in length. Some of these wells were drilled to depths of greater than 6000 m, and some were extended by more than 3000 m. During the process of drilling, the wellbore stability and drilling ability were poor and the time required for drilling was long. Complex accidents occurred frequently, which severely limited the drilling rate and became the main restriction on drilling speed. According to surveys, approximately 70%–80% of the drilling accidents were caused by wellbore instability. These accidents included collapses, sticking and leakage, indicating that wellbore stability was a primary challenge in efficient development of the Nanpu oilfield. Wellbore instability during drilling is related to shale hydration (Nesbitt et al1985, Ballard et al1994). Wellbore instability is influenced by synergies between mechanical and chemical factors. When the drilling fluid comes in contact with mudstone and shale formations, physical and chemical reactions between the clay minerals in mudstone and shale formations and the water occur, resulting in hydration of the shale. The shale hydration reduces the shale’s strength and causes changes relative to the original stress state adjacent to the well bore. Eventually, it causes wellbore instability. Wellbore instability affects the drilling rate and completion; it also pollutes the formations containing the oil and gas reservoirs and induces downhole accidents, resulting in increases in drilling costs and hindering the exploration and development of oil and gas reservoirs. Statistical results show that over 90% of wall collapses occur in mud shale formations (Shi et al2012a, 2012b). Mudstone and shale formations can be divided into stronger swelling mudstone and shale formations, which more readily exhibit hydration swelling and wellbore shrinkage and contain mainly montmorillonite, and weaker swelling mudstone and shale formations, which more readily spall and collapse and contain mainly illite. Therefore, the wellbore instability mechanism in weaker swelling shale formations differs from the wellbore instability mechanism in stronger swelling shale formations (Liang et al2015a). Weaker swelling shales do not disintegrate into rock fragments; instead, they break into pieces when the weaker swelling shales are exposed to water. They are also hard and brittle and have poor dispersion. Therefore, weaker swelling shales can be called hard brittle shales (Shi et al2012a, 2012b, Liang et al2015a). To determine the microstructural and physico-chemical properties of hard brittle shales, many researchers have carried out extensive studies. Shi et al (2012a, 2012b) utilised CT image digital core analysis to determine the microstructure of hard brittle shales from the Xujiahe Formation and to obtain the pattern of change in the microstructure caused by shale hydration. Based on analysis of the physical–chemical properties of shales from the Weizhou Formation, Yue et al (2005) proposed the use of strong, fast-sealing and film-forming drilling fluid to prevent falling blocks in hard brittle shale formations. Gomez and He (2012) carried out research on the physical–chemical properties of hard brittle shales and characterised the interaction between hard brittle shales and drilling fluid. Liu et al (2014) obtained the effects of wettability on wellbore stability and mechanical properties of shales from the Longmaxi Formation. Liang et al (2015a, 2015b) studied the influence of physical–chemical properties and shale hydration on wellbore stability. Elijah et al (2011) utilised NMR technology to investigate wettability and its influence on hard brittle shales. Roychaudhuri et al (2013) studied spontaneous imbibition in shales from the Marcellus Formation. Dehghanpour et al (2013) investigated the spontaneous imbibition of water in shales from the Horn River Formation. Ma and Chen (2014) used CT technology to evaluate shale hydration effects in hard brittle shales from the Longmaxi Formation. Yuan et al (2014) investigated the wettability and water adsorption capacity of shales from the Longmaxi Formation. Sun et al (2015) investigated the imbibition behaviour of shales from the Marcellus Formation. Xiong et al (2016) examined the influence of physical–chemical properties and shale hydration on wellbore stability in hard brittle shales from the Dongying Formation. Wen et al (2015) carried out a study of the effects of interactions between water and rock on the mechanical properties of hard brittle shales from the Longmaxi Formation. All those studies have investigated different aspects of the physical–chemical properties and mechanical properties of hard brittle shales. However, there are few studies that examine the physico-chemical and mechanical properties of the hard brittle shales from the Shahejie Formation in the Nanpu Sag. In this work, we investigated the physico-chemical and mechanical properties of the hard brittle shales from the Shahejie Formation in the Nanpu Sag in the Bohai Bay Basin of northern China, including mineralogical characteristics, microstructural characteristics, physico-chemical characteristics and mechanical characteristics. We examined core samples from the Nanpu oilfield in the Bohai Bay Basin by applying x-ray diffraction (XRD) analysis, cation exchange capacity (CEC) analysis, contact angle measurements, scanning electron microscope (SEM) observations, immersion experiments, ultrasonic testing and mechanical testing. The influence of the physico-chemical properties of the Shahejie Formation shales on wellbore instability is investigated, and the interactions between water and the Shahejie Formation shales and their influence on wellbore instability are also discussed. We hope that our research offers data and a reference that will be useful in further study of wellbore stability in the Nanpu oilfield. 2. Samples and methods 2.1. Experimental samples Core samples of hard brittle shale were collected from the Shahejie Formation in the Nanpu Sag in the Bohai Bay Basin of northern China and cover four different areas in the Nanpu Sag. The sample numbers, depths and well names are shown in table 1. Composition and structure indicate the position and morphology of all components. These terms normally describe the relative amounts of particles, crystals and cement. Mineral composition, types of clay minerals present, microstructures and physical–chemical properties are key factors that control the mechanical properties of the shales. Therefore, measuring and analysing mineral compositions, microstructures and physical–chemical properties are beneficial for optimising drilling fluid mixtures. Meanwhile, it is desirable for us to have a deep understanding of wellbore instability mechanisms. Therefore, the samples are necessary to describe the mineralogical characteristics, pore structure characteristics and physico-chemical characteristics. A relatively complete experimental programme was conducted that included XRD analysis, CEC analysis, contact angle measurements, SEM observations, immersion experiments, ultrasonic testing and mechanical testing. Table 1. Locations of shale samples from the Shahejie Formation in the Nanpu Sag. Area . Sample no. . Well name . Vertical depth (m) . Area . Sample no. . Well name . Vertical depth (m) . Area 1 1 NP1 3778.3 Area 2 7 NP3-82 4920.0 2 NP3-15 4651.8 Area 3 8 NP401 3523.3 3 NP3-27 4750.9 9 NP5-81 4900.0 Area 2 4 NP3-81 4766.6 Area 4 10 NP5-82 4149.9 5 NP3-81 5545.5 11 NP5-96 3903.1 6 NP3-82 4731.1 Area . Sample no. . Well name . Vertical depth (m) . Area . Sample no. . Well name . Vertical depth (m) . Area 1 1 NP1 3778.3 Area 2 7 NP3-82 4920.0 2 NP3-15 4651.8 Area 3 8 NP401 3523.3 3 NP3-27 4750.9 9 NP5-81 4900.0 Area 2 4 NP3-81 4766.6 Area 4 10 NP5-82 4149.9 5 NP3-81 5545.5 11 NP5-96 3903.1 6 NP3-82 4731.1 Open in new tab Table 1. Locations of shale samples from the Shahejie Formation in the Nanpu Sag. Area . Sample no. . Well name . Vertical depth (m) . Area . Sample no. . Well name . Vertical depth (m) . Area 1 1 NP1 3778.3 Area 2 7 NP3-82 4920.0 2 NP3-15 4651.8 Area 3 8 NP401 3523.3 3 NP3-27 4750.9 9 NP5-81 4900.0 Area 2 4 NP3-81 4766.6 Area 4 10 NP5-82 4149.9 5 NP3-81 5545.5 11 NP5-96 3903.1 6 NP3-82 4731.1 Area . Sample no. . Well name . Vertical depth (m) . Area . Sample no. . Well name . Vertical depth (m) . Area 1 1 NP1 3778.3 Area 2 7 NP3-82 4920.0 2 NP3-15 4651.8 Area 3 8 NP401 3523.3 3 NP3-27 4750.9 9 NP5-81 4900.0 Area 2 4 NP3-81 4766.6 Area 4 10 NP5-82 4149.9 5 NP3-81 5545.5 11 NP5-96 3903.1 6 NP3-82 4731.1 Open in new tab In this study, there were 11 core samples from different wells in the Nanpu Sag could be used for XRD analysis, CEC analysis was conducted on 11 core samples, contact angle measurements were taken on 11 core samples, 4 core samples could be adopted to do SEM observations, 6 core samples could be used in immersion testing, and ultrasonic testing was conducted on 3 core samples. In addition, researchers also collected 6 core samples from different wells in the Nanpu Sag for mechanical testing. 2.2. Experimental methods The samples were crushed to 100 mesh-size grains for XRD analysis with an X’Pert PRO. The mineralogical compositions and relative mineral percentage of the samples were estimated following the Chinese Oil and Gas Industry Standards SY/T5983-1994 and SY/T5163-1995. The samples were crushed to 100 mesh-size grains for CEC analysis. The methylene blue test shown in equation (1) was used to calculate the CEC of the investigated shales. The experimental process followed the Chinese Oil and Gas Industry Standards SY/T 5613-2000 and SY/T 5613-93. CEC=a/b×100.1 In the above equation, CEC is the cation exchange capacity of the shales; a is one millilitre of methylene blue solution; and b is the mass in grams of the shale during the titration process. We performed wettability experiments to investigate the wetting behaviour of the samples. The contact angle measurements were used to quantitatively evaluate wettability. The gas–liquid–rock contact angles were measured using a DSA100 optical contact angle-measuring instrument. Additionally, the contact angle measurement liquid was water. To observe the mode of occurrence and arrangement of clay minerals in the investigated shales, as well as the microstructural characteristics of the investigated shales, we utilised a Quanta 450 SEM in high vacuum scanning mode. Using different working voltages, the Quanta 450 can reach a resolution ratio of 3 nm and has a magnification power of 25–200 000×. To prepare the samples, we etched their surfaces with argon ion polishing to create a mirror surface. This procedure avoids the damage caused by normal polishing techniques and maintains the true pore morphology. Finally, we applied a gold film to the sample surfaces. To investigate the influence of the interactions between water and the shales (that is, hydration by spontaneous imbibition) on the microstructure and macroscopic shape of the investigated shales, eight groups of immersion experiments were conducted. The immersion liquid was deionized water (here termed simply water) and the conditions matched the ambient temperature and pressure. During the immersion experiments, the formation and distribution of cracks on the sample surfaces were recorded, and the hydration of the samples was analysed to determine the rupture process for the investigated shale samples caused by shale hydration. The experiments could be used to observe changes in the macroscopic shapes of the investigated shale samples, which were large samples. On this basis, we used a high-powered microscope to investigate the changes in the microstructure of the investigated shale samples caused by shale hydration. The experiments could be used to analyse the mechanisms of crack initiation and propagation induced by shale hydration. Samples with thin sections with a diameter of 25 mm and a thickness of 3 mm were examined, and these thin sections should be polished to be even and smooth. Furthermore, acoustic testing was conducted before and after immersion to obtain the acoustic characteristic of the investigated shales after different immersion times and to determine the influence of shale hydration on the acoustic characteristics of the investigated shales. To obtain the mechanical properties, the hardness and triaxial tests were conducted before and after immersion. First, the hardness and triaxial tests were applied to the shale rock without immersion. After immersion in the drilling fluid, the hardness and triaxial tests were then applied again. The above tests are intended to determine the changes in rock mechanical properties after different immersion times and to assess the influence of shale hydration on mechanical properties. 3. Results 3.1. Mineralogical compositions The results of XRD analysis of the shale samples from four different areas in the Nanpu Sag are shown in table 2. These samples show a wide range of mineralogical compositions. The samples are mainly composed of quartz, feldspar (orthoclase and plagioclase), carbonates (calcite and dolomite), clay minerals (illite, mixed-layer illite/smectite, kaolinite and chlorite), and a small amount of siderite. In table 2, we observe that the clay mineral contents of the investigated shale samples are between 25.33% and 57.49%, with a mean value of 42.49%; the quartz contents range from 20.03% to 46.45%, with an average of 33.80%; the feldspars contents are 0%–18.42%, with a mean value of 10.31%; and the average carbonate content is 12.17% and ranges from 0% to 24.64%. The clay minerals are primarily illite and mixed-layer illite/smectite, the average illite content is over 51%, and the mixed-layer illite/smectite content averaged 31%. The presence of swelling clay minerals is not observed, such as montmorillonite. This is also observed in Dehghanpour et al (2013), Yuan et al (2014), Liang et al (2015a, 2015b). These findings indicate that the investigated shales differ from the stronger swelling shales, which contain mainly montmorillonite. Table 2. Results of XRD analysis of the shale samples. . Mineralogical compositions by relative weight (%) . Sample no. . Quartz . Orthoclase . Plagioclase . Calcite . Dolomite . Siderite . Ia . I/Sb . Kc . Cd . 1 20.03 4.41 0.00 11.56 3.09 3.42 32.97 8.04 16.48 0.00 2 37.60 0.00 8.88 6.16 0.00 4.08 17.45 19.95 0.00 5.88 3 30.99 0.00 11.94 4.62 5.11 0.00 24.10 19.66 0.00 3.58 4 27.27 0.00 3.30 8.50 5.99 2.91 33.38 15.59 0.00 3.06 5 41.41 2.23 14.61 0.00 0.00 0.00 27.04 8.48 1.04 5.19 6 29.45 9.31 9.11 12.06 10.22 0.00 15.72 10.82 0.60 2.71 7 28.81 0.00 0.00 3.84 12.79 3.08 24.50 23.71 0.00 3.27 8 32.56 4.15 6.57 2.23 7.79 0.00 18.01 25.13 3.47 1.09 9 39.94 0.00 12.21 1.71 3.08 0.00 21.43 9.44 2.70 9.49 10 37.30 12.73 0.00 14.39 10.25 0.00 14.32 1.70 0.00 9.31 11 46.45 6.42 7.54 9.07 1.44 0.00 10.03 11.56 3.09 4.40 . Mineralogical compositions by relative weight (%) . Sample no. . Quartz . Orthoclase . Plagioclase . Calcite . Dolomite . Siderite . Ia . I/Sb . Kc . Cd . 1 20.03 4.41 0.00 11.56 3.09 3.42 32.97 8.04 16.48 0.00 2 37.60 0.00 8.88 6.16 0.00 4.08 17.45 19.95 0.00 5.88 3 30.99 0.00 11.94 4.62 5.11 0.00 24.10 19.66 0.00 3.58 4 27.27 0.00 3.30 8.50 5.99 2.91 33.38 15.59 0.00 3.06 5 41.41 2.23 14.61 0.00 0.00 0.00 27.04 8.48 1.04 5.19 6 29.45 9.31 9.11 12.06 10.22 0.00 15.72 10.82 0.60 2.71 7 28.81 0.00 0.00 3.84 12.79 3.08 24.50 23.71 0.00 3.27 8 32.56 4.15 6.57 2.23 7.79 0.00 18.01 25.13 3.47 1.09 9 39.94 0.00 12.21 1.71 3.08 0.00 21.43 9.44 2.70 9.49 10 37.30 12.73 0.00 14.39 10.25 0.00 14.32 1.70 0.00 9.31 11 46.45 6.42 7.54 9.07 1.44 0.00 10.03 11.56 3.09 4.40 a I = Illite. b I/S = mixed-layer illite/smectite. c K = Kaolinite. d C = Chlorite. Clay minerals = I + I/S + K + C. Open in new tab Table 2. Results of XRD analysis of the shale samples. . Mineralogical compositions by relative weight (%) . Sample no. . Quartz . Orthoclase . Plagioclase . Calcite . Dolomite . Siderite . Ia . I/Sb . Kc . Cd . 1 20.03 4.41 0.00 11.56 3.09 3.42 32.97 8.04 16.48 0.00 2 37.60 0.00 8.88 6.16 0.00 4.08 17.45 19.95 0.00 5.88 3 30.99 0.00 11.94 4.62 5.11 0.00 24.10 19.66 0.00 3.58 4 27.27 0.00 3.30 8.50 5.99 2.91 33.38 15.59 0.00 3.06 5 41.41 2.23 14.61 0.00 0.00 0.00 27.04 8.48 1.04 5.19 6 29.45 9.31 9.11 12.06 10.22 0.00 15.72 10.82 0.60 2.71 7 28.81 0.00 0.00 3.84 12.79 3.08 24.50 23.71 0.00 3.27 8 32.56 4.15 6.57 2.23 7.79 0.00 18.01 25.13 3.47 1.09 9 39.94 0.00 12.21 1.71 3.08 0.00 21.43 9.44 2.70 9.49 10 37.30 12.73 0.00 14.39 10.25 0.00 14.32 1.70 0.00 9.31 11 46.45 6.42 7.54 9.07 1.44 0.00 10.03 11.56 3.09 4.40 . Mineralogical compositions by relative weight (%) . Sample no. . Quartz . Orthoclase . Plagioclase . Calcite . Dolomite . Siderite . Ia . I/Sb . Kc . Cd . 1 20.03 4.41 0.00 11.56 3.09 3.42 32.97 8.04 16.48 0.00 2 37.60 0.00 8.88 6.16 0.00 4.08 17.45 19.95 0.00 5.88 3 30.99 0.00 11.94 4.62 5.11 0.00 24.10 19.66 0.00 3.58 4 27.27 0.00 3.30 8.50 5.99 2.91 33.38 15.59 0.00 3.06 5 41.41 2.23 14.61 0.00 0.00 0.00 27.04 8.48 1.04 5.19 6 29.45 9.31 9.11 12.06 10.22 0.00 15.72 10.82 0.60 2.71 7 28.81 0.00 0.00 3.84 12.79 3.08 24.50 23.71 0.00 3.27 8 32.56 4.15 6.57 2.23 7.79 0.00 18.01 25.13 3.47 1.09 9 39.94 0.00 12.21 1.71 3.08 0.00 21.43 9.44 2.70 9.49 10 37.30 12.73 0.00 14.39 10.25 0.00 14.32 1.70 0.00 9.31 11 46.45 6.42 7.54 9.07 1.44 0.00 10.03 11.56 3.09 4.40 a I = Illite. b I/S = mixed-layer illite/smectite. c K = Kaolinite. d C = Chlorite. Clay minerals = I + I/S + K + C. Open in new tab Furthermore, we can note that the compositions of the 4 areas in the Nanpu Sag are different from each other, indicating that the composition of the investigated shales varies spatially. These findings indicate that all of the Shahejie Formation shales are primarily composed of quartz and clay minerals, and the clay minerals are predominantly illite and mixed-layer illite/smectite. 3.2. CEC The CEC of shales is directly related to their water adsorption capacity and surface hydration, which reflect the hydration expansion capacity of the shales. Therefore, CEC analysis was used to investigate the hydration expansion capacity of the shales (Liang et al2015b). The results of the methylene blue test of selected samples are shown in figure 1. Using equation (1), the values of the CEC can be obtained, and these values are presented in figure 2 and table 3. From figure 2 and table 3, we could observe that the values of the CEC range from 90 to 210 mmol kg-1, with an average of 150.7 mmol kg-1. The CEC of the investigated shales is more than 100 mmol kg-1, indicating that the investigated shales have some hydration expansion. This may be related to the elevated amounts of mixed-layer illite/smectite in the investigated shales. According to previous work (Liang et al2015b), the CEC value of the investigated shales is larger than that of the Longmaxi Formation shales, suggesting that the average CEC value is 94.69 mmol kg-1. This may be because that there are less mixed-layer illite/smectite contents and more illite contents in the Longmaxi Formation shales. In addition, the CEC values vary spatially, which is consistent with the spatial variations in composition noted above. Figure 1. Open in new tabDownload slide Titration image showing the results of the methylene blue test for selected samples. Figure 1. Open in new tabDownload slide Titration image showing the results of the methylene blue test for selected samples. Figure 2. Open in new tabDownload slide CEC values of the samples. Figure 2. Open in new tabDownload slide CEC values of the samples. Table 3. CEC values of the investigated shale samples. . CEC mmol-1 kg-1 . . CEC mmol-1 kg-1 . Area . Min . Max . Ave . Area . Min . Max . Ave . Area 1 143.5 167.5 155.5 Area 3 165 210 186.7 Area 2 120 177.5 147.5 Area 4 90 110 116.7 . CEC mmol-1 kg-1 . . CEC mmol-1 kg-1 . Area . Min . Max . Ave . Area . Min . Max . Ave . Area 1 143.5 167.5 155.5 Area 3 165 210 186.7 Area 2 120 177.5 147.5 Area 4 90 110 116.7 Open in new tab Table 3. CEC values of the investigated shale samples. . CEC mmol-1 kg-1 . . CEC mmol-1 kg-1 . Area . Min . Max . Ave . Area . Min . Max . Ave . Area 1 143.5 167.5 155.5 Area 3 165 210 186.7 Area 2 120 177.5 147.5 Area 4 90 110 116.7 . CEC mmol-1 kg-1 . . CEC mmol-1 kg-1 . Area . Min . Max . Ave . Area . Min . Max . Ave . Area 1 143.5 167.5 155.5 Area 3 165 210 186.7 Area 2 120 177.5 147.5 Area 4 90 110 116.7 Open in new tab 3.3. Wettability The contact angles of the investigated shale samples are presented in figure 3 and table 4. It can easily be seen that the wettability of the investigated shales is strongly water-wetted in the gas–liquid–rock system, as indicated by the low contact angle, which is less than 30°. Furthermore, we can see that the capillary force drives water flow, indicating that the water would enter into the shales by imbibition absorption under the influence of the capillary force when the shales come in contact with water. When water enters into the micro-fractures in the shales, the capillary force creates a wedge effect, and when it comes into contact with clay minerals, hydration and wedging effects occur at the crack tip, causing wellbore instability. This observation is consistent with previous studies on other shale samples (Dehghanpour et al2013, Yuan et al2014, Sun et al2015). However, the finding is in disagreement with previous research on Longmaxi Formation shales (Liang et al2015a, 2015b), indicating that the wettability of the Longmaxi Formation shales was mixed and inclined towards oil-wetting. This may be because that the Longmaxi Formation shales is rich in organic matter. Figure 3. Open in new tabDownload slide Experimental contact angle results for the investigated shale samples. Figure 3. Open in new tabDownload slide Experimental contact angle results for the investigated shale samples. Table 4. Experimental contact angle results for the investigated shale samples. . Contact angle . . Contact angle . Sample no. . CA(L)/°a . CA(R)/°b . Sample no. . CA(L)/°a . CA(R)/°b . 1 6.3 6.3 7 17.4 17.4 2 8.9 8.9 8 6.1 6.1 3 23.1 23.1 9 10.4 10.4 4 7.2 7.2 10 14.3 14.3 5 5.7 5.7 11 15.4 15.4 6 25.8 25.8 . Contact angle . . Contact angle . Sample no. . CA(L)/°a . CA(R)/°b . Sample no. . CA(L)/°a . CA(R)/°b . 1 6.3 6.3 7 17.4 17.4 2 8.9 8.9 8 6.1 6.1 3 23.1 23.1 9 10.4 10.4 4 7.2 7.2 10 14.3 14.3 5 5.7 5.7 11 15.4 15.4 6 25.8 25.8 a Left contact angle. b Right contact angle. Open in new tab Table 4. Experimental contact angle results for the investigated shale samples. . Contact angle . . Contact angle . Sample no. . CA(L)/°a . CA(R)/°b . Sample no. . CA(L)/°a . CA(R)/°b . 1 6.3 6.3 7 17.4 17.4 2 8.9 8.9 8 6.1 6.1 3 23.1 23.1 9 10.4 10.4 4 7.2 7.2 10 14.3 14.3 5 5.7 5.7 11 15.4 15.4 6 25.8 25.8 . Contact angle . . Contact angle . Sample no. . CA(L)/°a . CA(R)/°b . Sample no. . CA(L)/°a . CA(R)/°b . 1 6.3 6.3 7 17.4 17.4 2 8.9 8.9 8 6.1 6.1 3 23.1 23.1 9 10.4 10.4 4 7.2 7.2 10 14.3 14.3 5 5.7 5.7 11 15.4 15.4 6 25.8 25.8 a Left contact angle. b Right contact angle. Open in new tab 3.4. SEM imaging The SEM images of the microstructures of the investigated shale samples are presented in figure 4. Based on figure 4(a), the shales have flaky clay mineral particles that are aligned in the direction of bedding. In addition, figures 4(b)–(d) show that the shales have well-developed micro-cracks. From the point of view of rock mechanics, the presence of micro-cracks in the shales would destroy the integrity of the shales and then weaken the mechanical properties of the shales. In addition, in the process of drilling, the micro-cracks could provide a space for fluid invasion and provide hydration space. Therefore, when the investigated shale samples contact with hydrophilic fluid, the capillary force determined by the capillary effect would provide power for the water, the micro-cracks would offer flowing channels to the water, and then the water would enter inside the investigated shale samples. Figure 4. Open in new tabDownload slide SEM images of the shale samples: (a) flaky clay mineral particles; (b)–(d) micro-cracks. Figure 4. Open in new tabDownload slide SEM images of the shale samples: (a) flaky clay mineral particles; (b)–(d) micro-cracks. 3.5. Immersion experiments The results of the immersion experiments performed on the samples are illustrated in figure 5. These results indicate that the samples are highly hydrated and have developed several obvious fractures on their surfaces after immersion in water, and mainly describe the macroscopic shapes of the samples before and after immersion. From figure 5, after immersion in the fluid, the shale samples show physical alteration. That is, all the shale samples specimens are damaged. The macroscopic shapes of the samples before and after immersion are clearly different. The integrity is damaged in some parts of the specimens, which contain macroscopic fractures that lead to shale failure. On the other hand, some of the specimens maintain their integrity. Even though they contain a few fractures, these fractures do not cause failure. These findings are in agreement with those of previous research on other shale samples (Dehghanpour et al2013, Liang et al2015a, Sun et al2015). Based on our previous work (Liang et al2015a), we showed that the capillary effect and hydration positively impact the water-induced crack propagation mechanism for shales from the Longmaxi Formation. The physical alteration of the shales indicates that shale hydration would occur when the shales come into contact with water. However, the degree of shale hydration varies. When the clay minerals particles in the shales adsorb water molecules and then form surface hydration shells, it results in hydration stress induction. The hydration stress and the capacity effect increase the stresses at the tips of cracks, making it easier for cracks to expand and extend. As the immersion time increases, small cracks expand to form macroscopic cracks. When this expansion proceeds to a certain point, it stops and maintains the shale rock integrity. These immersion experiments suggest that the hydration characteristics of the hard brittle shales are different from those of stronger swelling shales, which normally have weak deformation characteristics and do not show cracks when immersed in fluid. Figure 5. Open in new tabDownload slide Comparison of shale samples before and after the immersion experiments. Figure 5. Open in new tabDownload slide Comparison of shale samples before and after the immersion experiments. The microscopic images showing the initiation and propagation of cracks within the shale samples caused by hydration are shown in figure 6. From figure 6, we can see that the water initially invades into the shales along the original micro-cracks when the shales come into contact with the water through the high-powered microscope. With increasing contact time, cracks begin to form on the surfaces of the shale samples, and the crack shape is irregular. After the cracks form, the edges of the cracks are wetted by water because of hydrophilic and spontaneous imbibition. The water invades into the shales along the water-induced cracks, causing those cracks to have surfaces that form dark black stripes in the microscope images. However, the surfaces of shale samples with no cracks remain dry. This finding indicates that those water-induced cracks could provide space for fluid flow paths. With the invasion of water along those water-induced cracks, the cracks continuously propagate ahead and gradually widen until the rock particles completely separate from each other, indicating that those cracks would spread to other zones of the shale sample surface. Furthermore, it can be seen from figure 6 that those water-induced cracks are sufficiently characterised by tension failure and the boundaries of those cracks are similar to those of other cracks. This conclusion indicates that extensional stress concentrates at the tip of the crack, resulting in the extension and propagation of the crack. This may be related to the capillary effect and hydration (Liang et al2015a). Figure 6. Open in new tabDownload slide Microscope images showing the initiation and propagation of cracks. Figure 6. Open in new tabDownload slide Microscope images showing the initiation and propagation of cracks. 3.6. Ultrasonic testing To investigate the influence of shale hydration on the acoustic characteristics of the shales, shale specimens were taken from the Nanpu Sag to do immersion experiments. The purpose of immersion experiments is to determine the influence of shale hydration time on macroscopic cracks (physical alteration). Meanwhile, a longitudinal frequency (250 kHz) was applied to conduct acoustic testing in order to determine the influence of shale hydration time on the acoustic properties of the shales. The macroscopic morphologies before and after immersion are illustrated in figure 7. The corresponding acoustic travel time values are shown as figure 8. Based on figure 7, when the water came into contact with the shales, physical and chemical reactions between the clay minerals in the shales and the water occur, resulting in the induction of shale hydration. With an increase in the immersion time, the shale hydration become stronger, causing the cracks to extend and bifurcate into new cracks. From figure 8, the acoustic travel time of the shales had the same growth trend that implied an increased immersion time. The main reason for that behaviour is that shale hydration occurs when the water is in contact with the shales. This shale hydration induces micro-cracks (figure 6), which change the microstructure, leading to changes in the acoustic travel time. With the increase of the immersion time, stronger shale hydration leads to more cracks and bigger growth in the range of shale acoustic travel time. Furthermore, we can observe from figure 8 that the acoustic travel time of the shale samples was too large after immersion for 18 h, which belonged the reasonable range, especially shale sample no. 2-1. This may be because that after immersion for 12 h, we could observe that there were obviously several macroscopic fractures on the surface of the shale samples, and then we used the transparent tape around on the shale samples in order to prevent form breaking into pieces, indicating that the experimental conditions in the experiments might change; after immersion for 18 h, the macroscopic shape of the shale samples could change, that is to say, the integrity of the shale samples was damaged. Therefore, affected by the macroscopic shape varied and experimental condition changed, the acoustic travel time of the investigated shales after immersion for 18 h exceeded the reasonable range. In a words, from the qualitative perspective, the acoustic travel time of the investigated shales increased as the immersion time increases. In addition, we can conclude that shale hydration has a strong impact on the acoustic travel time of the investigated shales, and the changes in the acoustic travel time can reflect the shale hydration degree. Therefore, acoustic logging data collected during acoustic logging or well logging during drilling need to eliminate this impact of shale hydration. Figure 7. Open in new tabDownload slide Comparison of observations before and after the immersion experiments were applied to the shale samples. Figure 7. Open in new tabDownload slide Comparison of observations before and after the immersion experiments were applied to the shale samples. Figure 8. Open in new tabDownload slide Acoustic travel times before and after the immersion experiments for the shale samples. Figure 8. Open in new tabDownload slide Acoustic travel times before and after the immersion experiments for the shale samples. 3.7. Mechanical testing Due to the differences in clay mineral compositions, microstructures and physical–chemical properties, different types of fluid could cause different impacts on the macroscopic and microcosmic structures, leading to various influences on the rock’s mechanical properties. Based on the fractures that appear after they come into contact with the water, the hardness test and triaxial test are applied to obtain the influence of shale hydration on rock mechanical properties. The method used in the hardness test involves the use of a pressure head to press into the rock. In this test, the maximum pressure value is the rock hardness. The results of the hardness test for the hard brittle shales from the 4 areas are illustrated in figure 9. Based on figure 9, the hardness of the shale samples showed some differences, which may be related to the depositional environment. These differences indicate that the hard brittle shales in the Nanpu Sag show strong anisotropy. The results of the hardness test after immersion are shown in figure 10. The hardness value of the shales before immersion was higher in the 4 areas. After immersion, the hardness value went down and the decline in the range became bigger with increasing immersion time. When the shales came into contact contact with the water, the capillary effect caused water to enter the rock through micro-cracks. Physical and chemical reactions between the clay minerals in the shales and the water then occurred, which resulted in shale hydration and led to damage, which made the hardness of the shales drop. The damage is more obvious in that the decline in the range is bigger. This finding indicates that shale hydration causes the strength of the shales to decline, and the decline increases with increasing hydration time. Figure 11 illustrates the same conclusion, the change in hardness before and after immersion was the same at different confining pressures. That is, the compressive pressure decreases with increasing immersion time. The results of the triaxial tests are shown in table 5. Based on table 5, with increasing immersion time, the elasticity modulus showed a declining trend, and the Poisson ratio showed an increasing trend. In addition, the cohesion and the internal friction angle decreased with increasing immersion time, indicating that shale hydration was capable of reducing the shale’s strength. The above results shows that shale hydration can cause damage and decrease strength, leading to wellbore instability. In addition, with increasing time, the damage is more obvious and the strength decline is more pronounced, aggravating the instability. Figure 9. Open in new tabDownload slide Hardness of the shale samples. Figure 9. Open in new tabDownload slide Hardness of the shale samples. Figure 10. Open in new tabDownload slide Hardness values before and after immersion experiments were applied to the shale samples ((a), area 1; (b), area 2; (c), area 3; (d), area 4). Figure 10. Open in new tabDownload slide Hardness values before and after immersion experiments were applied to the shale samples ((a), area 1; (b), area 2; (c), area 3; (d), area 4). Figure 11. Open in new tabDownload slide Measured compressive strength values before and after immersion experiments for the shale samples. Figure 11. Open in new tabDownload slide Measured compressive strength values before and after immersion experiments for the shale samples. Table 5. Results of mechanical testing of the shale samples. Conditions . Confining pressure/MPa . Compressive strength/MPa . Elasticity modulus/MPa . Poisson’s ratio . Internal friction angle/° . Cohesion/MPa . Before immersion 0 30.8 29 547 0.228 24.89 9.83 50 153.5 33 396 0.239 After immersion for 6 h 0 23.8 27 927 0.290 23.09 7.86 50 138.3 35 807 0.313 After immersion for 12 h 0 21.5 35 138 0.337 21.42 7.32 50 129.0 32 948 0.351 Conditions . Confining pressure/MPa . Compressive strength/MPa . Elasticity modulus/MPa . Poisson’s ratio . Internal friction angle/° . Cohesion/MPa . Before immersion 0 30.8 29 547 0.228 24.89 9.83 50 153.5 33 396 0.239 After immersion for 6 h 0 23.8 27 927 0.290 23.09 7.86 50 138.3 35 807 0.313 After immersion for 12 h 0 21.5 35 138 0.337 21.42 7.32 50 129.0 32 948 0.351 Open in new tab Table 5. Results of mechanical testing of the shale samples. Conditions . Confining pressure/MPa . Compressive strength/MPa . Elasticity modulus/MPa . Poisson’s ratio . Internal friction angle/° . Cohesion/MPa . Before immersion 0 30.8 29 547 0.228 24.89 9.83 50 153.5 33 396 0.239 After immersion for 6 h 0 23.8 27 927 0.290 23.09 7.86 50 138.3 35 807 0.313 After immersion for 12 h 0 21.5 35 138 0.337 21.42 7.32 50 129.0 32 948 0.351 Conditions . Confining pressure/MPa . Compressive strength/MPa . Elasticity modulus/MPa . Poisson’s ratio . Internal friction angle/° . Cohesion/MPa . Before immersion 0 30.8 29 547 0.228 24.89 9.83 50 153.5 33 396 0.239 After immersion for 6 h 0 23.8 27 927 0.290 23.09 7.86 50 138.3 35 807 0.313 After immersion for 12 h 0 21.5 35 138 0.337 21.42 7.32 50 129.0 32 948 0.351 Open in new tab 4. Discussion 4.1. The influence of physico-chemical properties The results of XRD analysis of the Shahejie Formation shale samples from four different areas in the Nanpu Sag demonstrated the presence of the same major inorganic minerals, including quartz, clay minerals, feldspars and carbonates (table 2). The clay minerals do not include montmorillonite. However, the contents of the mixed-layer illite/smectite are high; they range from 6.72% to 47.38% and have a mean value of 31.88%. The results of CEC analysis of the Shahejie Formation shale samples indicate that the investigated shales have some hydration. Therefore, drilling fluid systems need to use increased amounts of clay-hydration inhibitor in order to prevent shale hydration during the process of drilling in the formation. Furthermore, the contact angle results for the investigated shale samples suggested that the wettability of the investigated shale was water-wet, indicating that water invades into the rock along micro-cracks by the capillary effect, and that shale hydration would occur when the water comes into contact with clay mineral particles. Therefore, active agents should be added to the drilling fluid system to change the wettability and decrease the filter loss, in order to reduce the effects of hydration. In addition, the SEM images suggested that there were well-developed micro-cracks in the formation. High contents of brittle minerals make a reservoir highly brittle and make it easier for fractures to develop (Liang et al2015b). The brittleness index of shale is given as brittleness = (Q + C)/(Q + C + Cly) (Diao 2013), where Q is the quartz content, C is the carbonate content, and Cly is the clay mineral content. The brittleness index values of the Shahejie Formation shale samples are shown in figure 12. The brittleness index of the shales ranges from 0.45 to 0.71 with an average of 0.53, indicating that the investigated shale has a relatively high brittleness index. Liang et al (2015b) suggested that hard brittle shales with high brittleness index values have a higher degree of fracture development. Micro-cracks in these shales destroy the shales’ integrity and make them weaker. Meanwhile, the micro-cracks offer a means for drilling fluid to enter into the shales and provide space for shale hydration. Driven by the drilling pressure, capillary force and chemical potential, fluid can enter into the formation along micro-cracks. This phenomenon reduces the binding force between fracture surfaces and also causes the water wedge effect. Eventually, it leads to formation damage and triggers wellbore collapsing. Based on past drilling efforts, 40 out of 62 accidents were caused by leakage. In addition, there are many falling blocks underground. After increasing the density of the drilling fluid, the problems with collapses persist, which means that increasing the density of the drilling fluid does not solve the problem of wellbore instability. Therefore, for this formation, the drilling fluid system needs to choose the right blocking agent to stop water invasion. The key to solving the instability problems in this formation is to use a drilling fluid system with good sealing ability that limits fluid loss and hydration to avoid water invasion. Figure 12. Open in new tabDownload slide Brittleness of the shale samples. Figure 12. Open in new tabDownload slide Brittleness of the shale samples. 4.2. The influence of the shale hydration When hard brittle shales come into contact with water, the capillary effect draws water into the shale. In addition, the water has a series of reactions with the clay minerals, resulting in a decrease in the cohesion among particles. This would cause a decline in cohesion and the internal friction angle. The clay mineral particles in the shales can adsorb the water molecules and then form surface hydration shells, resulting in stress induction by hydration. This hydration stress would cause stresses to concentrate at the crack tips. The stress concentration leads to crack propagation. Meanwhile, with increases in the degree of hydration, the strength of the rock declines and the hydration stress grows, causing the cracks to propagate further, which eventually forms macroscopic cracks. During the drilling process, the drilling fluid enters into the formation and causes hydration, creating cracks around the wellbore. It therefore increases the value of the acoustic travel time, as well as the need to eliminate this impact of hydration. In addition, these cracks can decrease the shale’s strength, which causes it to be easily broken by fluid scour and drilling disturbances and leads to collapses. Therefore, in addition to choosing the right type of drilling fluid system, reducing disturbances from the drilling tool and the incidence of surge pressures during drilling are key in preventing wellbore instability. 5. Conclusions For the investigated shales, the mineral assemblage includes mainly quartz and clay minerals, the average CEC value is 150.7 mmol kg-1, and the wettability is strongly water-wetted. The conclusions suggest that the shales are partly hydrated, and the water might enter into the shales. When the shales are exposed to fluid, changes in macroscopic shape and microstructure occur that are caused by shale hydration, resulting in the generation of damage in the shales, increases in the acoustic travel time and reductions in the shale’s strength. As the immersion time increases, the shale hydration effect gradually becomes stronger, which causes the mechanical properties of the investigated shales to reflect a gradual weakening. Acknowledgments This research was supported by Open Fund of State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation (Southwest Petroleum University) (PLN 0906), the United Fund Project of National Natural Science Foundation of China (Grant No. U1262209), the National Natural Science Foundation of China (Grant No. 51274172). 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TI - Investigation of the physico-chemical and mechanical properties of hard brittle shales from the Shahejie Formation in the Nanpu Sag, northern China
JF - Journal of Geophysics and Engineering
DO - 10.1088/1742-2140/aa5f83
DA - 2017-06-01
UR - https://www.deepdyve.com/lp/oxford-university-press/investigation-of-the-physico-chemical-and-mechanical-properties-of-cBc6mjTf0M
SP - 445
VL - 14
IS - 3
DP - DeepDyve
ER -