1 Introduction

With the increasing demand for oil and gas resources and the depletion of conventional oil and gas resources (Liu et al. 2020a, b, 2023a), unconventional oil and gas resources have become more important (Chen et al. 2023; Cui et al. 2023; Liu et al. 2021). Shale oil and gas are a crucial part of unconventional oil and gas resources (Liu et al. 2020c, 2019; Gao et al. 2023), driving global energy structure reform (Sun et al. 2018a, 2017; Meng et al. 2023a; Jiang et al. 2022). Shale oil and gas resources refer to the oil and natural gas resources stored in shale formations (Tao et al. 2023; Li et al. 2023). Shale is not only the source rock of oil and gas resources (Yu et al. 2023; Meng et al. 2023b; Lu et al. 2020; Ma et al. 2019), but also the reservoir rock of oil and gas resources (Liu et al. 2023b; Nie 2023; Yuan et al. 2023; Sun et al. 2018b). The mineral composition of shale reservoirs is complex (Shao et al. 2023; Shi et al. 2022; Sun et al. 2018d), and the impact mechanisms of various minerals on different fluids vary greatly (Wei et al. 2023a; Wei and Sheng 2022; Xie et al. 2022). In addition, the pore throat structure of shale is dense and the connectivity is complex (Yang et al. 2022a, 2022b; Liu et al. 2023c; Sun et al. 2019a). Exploring the mechanism of external fluid action in the pore throat structure has important scientific and engineering significance (Yang et al. 2023a; Liu et al. 2023d; Sun et al. 2019b).

Wei et al. (2023b) studied the spontaneous infiltration mechanism of shale and found that the pore throat structure has a significant impact on the infiltration of external fluids. Xie et al. (2023) studied the establishment method of three-dimensional digital shale core and analyzed the influence of microscale fractures on fluid infiltration. Lai et al. (2023) analyzed the stability of complex drilling fluids, providing basic parameters for establishing a fracturing fluid infiltration model. Wang et al. (2022a) analyzed the damage mechanism of fracturing fluid on pore throat structure and established a coupling model between pore throat structure and fracturing fluid. Yang et al. (2023b) established a classification system for fracturing fluids based on their filtration characteristics and explored the mechanical changes of continental shale along the longitudinal profile. Yang et al. (2023a) established a fluid structure coupling model for shale microscale and nanoscale pore throat structure and analyzed the influence of different nanofiber structures on the sealing effect. Zhou et al. (2022) studied the effect of hydration on the infiltration and absorption of external fluids from shale, and analyzed the spontaneous infiltration and absorption mechanism during the well closure process. Guo et al. (2018) studied the effect of polymer adsorption on pore throat properties in slick water, and analyzed the coupling relationship between adsorption concentration, pH, and polymer concentration. Zhou et al. (2024) studied the influence of external fluids on the pore throat structure of tight reservoirs and analyzed the evolution mechanism of permeability. Yang et al. (2022c) studied the influence of mineral types and pore throat structure on the flow pattern, and analyzed three flow patterns in porous media. Wang et al. (2022b) established a gas water infiltration exchange model based on the gas water interaction mode and conducted application analysis in shale reservoirs. Ding et al. (2023) studied the effect of clay minerals on infiltration and found that the fracturing fluid first entered microscale pores. Chen et al. (2020) studied the damage mechanism of water phase capture on shale reservoirs and analyzed the impact of salinity. Namaee-Ghasemi et al. (2023) studied the interaction mode between low salinity water injection and pore throat structure, and explored the evolution characteristics of contact angle based on the concept of separation pressure.

In summary, many scholars have explored the sensitivity of shale reservoirs to external fluids (Xiao et al. 2023; Assal et al. 2023; Guo et al. 2023), but there is relatively little comparative research on slick water and backflow fluid, and systematic experimental research on the sensitivity of carbonaceous shale has not yet been conducted (Elbahrawy et al. 2023; Hou et al. 2023; Men et al. 2023). Therefore, in this paper, shale core samples are selected from the Daning-Jixian block in the eastern edge of the Ordos Basin, China, and sensitivity evaluation experiments are conducted on external fluids (slick water and backflow fluid) with different types of shale microscale pore structures. Firstly, taking pure shale as the research object, the influence mechanism of slick water and backflow fluid on the pore throat structure of pure shale is explored. On this basis, taking carbonaceous shale as the research object, the mechanism of the influence of slick water and backflow fluid on the pore throat structure of carbonaceous shale is analyzed. Finally, a comparative analysis and summary are conducted on the sensitivity of different types of shale to external fluids. The research results of this article have guiding significance for the formulation of fracturing fluid and the design of fracturing process. At the same time, it provides basic analysis parameters for revealing the gas/water dynamic characteristics of infiltration/production during fracturing process of shale reservoirs.

2 Evaluation method for sensitivity of shale pore structure to external fluids.

In this paper, the high-frequency and low-field nuclear magnetic resonance instrument is used to conduct two-dimensional nuclear magnetic T2 spectrum testing on saturated formation water cores and saturated external fluids (such as slick water and backflow fluid) cores. According to the T2 spectrum, divide the bound water in organic matter and clay and extract the T2 spectrum of fluid signals in the pore space of the rock core. For saturated fluid cores, the T2 value is linearly related to the pore radius r, i.e. T2 = k·r. By comparing the T2 spectrum of fluid signals in the pore space of the rock core with the high-pressure mercury injection pore throat distribution test results of parallel samples, the conversion of T2 values to pore radius can be achieved, and the pore structure of the rock core can be determined based on the T2 spectrum of fluid signals in the pore space of the rock core, and therefore, quantitative identification of porosity and movable fluids corresponding to different sizes of pores (< 0.0l μm micropores; 0.01–0.1 μm small pores; 0.1–1.0 μm medium pores; > 1.0 μm large pores) before and after immersion in external fluids in shale cores has been achieved. At the same time, sensitivity evaluation indicators for shale pores of different sizes are established: total porosity change rate, microporous porosity change rate, small pore porosity change rate, mesoporous porosity change rate, and macropore porosity change rate. Finally, a quantitative evaluation of the sensitivity of pores of different sizes in carbonaceous shale to external fluids is achieved.

3 Sensitivity experiment of external fluids in pore structure.

Based on two-dimensional nuclear magnetic resonance testing technology, identification of movable fluids and microscopic pore structure characteristics in shale gas reservoirs can be achieved. By comparing and analyzing the characteristic changes in the movable fluid and microscale pore structure of shale gas reservoir cores before and after immersion in external fluids (such as slick water and backflow fluid), the sensitivity of the reservoir to external fluids can be evaluated. In this section, the experimental equipment, experimental conditions, and experimental steps are introduced.

3.1 Experimental materials, conditions, and equipment.

For the sensitivity evaluation experiment of shale pore structure to foreign fluids, different concentrations of neutral sliding water and backflow fluid are selected as external fluids. The density of neutral slick water (0.4% lotion drag reducer + 0.1% drainage aid + 0.06% APS) is 1.005 g/ml; the density of the backflow liquid is 1.070 g/ml; the temperature is 71.8 °C; The experimental pressure is 18 MPa; the density of formation water is 1.101 g/ml. The selected core foundation parameters and experimental plan are detailed in Table 1. It should be noted that in order to reveal the influence of foreign fluids on carbonaceous shale, pure shale is also studied to enhance contrast. As shown in Table 1. The first to fourth groups are sensitivity evaluation experiments for external fluids in pure shale, while the fifth to eighth groups are sensitivity evaluation experiments for external fluids in carbonaceous shale.

Table 1 Basic parameters and experimental plan of rock cores
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The experimental equipment and instruments mainly include: high-precision desktop two-dimensional nuclear magnetic resonance instrument, high-temperature and high-pressure displacement device, high-pressure mercury intrusion meter, X-ray diffractometer, one thousandth high-precision balance, hand pump, pressure gauge, and core gripper.

3.2 Experimental methods and steps.

Based on the established method for evaluating the sensitivity of shale gas reservoir pore structure to external fluids, experimental steps for evaluating the sensitivity of shale gas reservoir pore structure have been developed:

  1. (a)

    Prepare rock cores columns with a diameter of 2.5 cm and a length of 5 cm using a wire cutting instrument. The remaining samples are subjected to high-pressure mercury intrusion and XRD testing. Prepare formation water and external fluids (slick water, backflow fluid) for the experiment.

  2. (b)

    Shale cores are dried to constant weight at 60 °C (with no change in mass after 4 h) and subjected to nuclear magnetic resonance testing.

  3. (c)

    Place the rock cores into a rock core gripper (with a confining pressure of 2 MPa) and vacuum it for 48 h. Under the conditions of reservoir temperature (71.8 °C) and pressure (18 MPa), saturate cores with formation water. Remove the rock cores, weigh it, and perform nuclear magnetic resonance testing.

  4. (d)

    Dry the rock cores at 60 °C to a constant weight.

  5. (e)

    Insert the rock cores into the gripper and apply a confining pressure of 2 MPa. After vacuuming for 48 h, saturate cores with external fluid. Conduct external fluid immersion experiments under reservoir temperature (71.8 °C) and pressure (18 MPa) conditions. After 48 h of experiment, the rock cores are taken out for weighing and nuclear magnetic resonance testing.

  6. (f)

    Dry the rock core at 60 °C to constant weight and conduct XRD testing.

  7. (g)

    Repeat steps (a)–(f) to conduct experiments on the sensitivity of different types of shale cores to different external fluids.

  8. (h)

    Clarify the changes in mineral composition of the cores before and after the experiment. Quantify the porosity and movable fluids corresponding to different pore sizes (< 0.0l μm micropores; 0.01–0.1 μm small pores; 0.1–1.0 μm medium pores; > 1.0 μm large pores) in shale cores after saturation with formation water and external fluids (such as slick water and backflow fluid). Based on the established sensitivity evaluation indicators for shale pores of different sizes, quantitatively evaluate the sensitivity of shale pores of different sizes to external fluids.

4 Results and discussion

4.1 Sensitivity of pure shale pore structure to variable viscosity slick water.

The influence of variable viscosity slick water on the pore structure of pure shale is studied using core 24–5–1–1 and core 4–13–3–1. Figure 1 shows the T2 spectrum of pure shale under dry samples, saturated formation water, and variable viscosity slick water conditions. As mentioned earlier, by comparing the T2 spectrum of fluid signals in the pore spaces of core 24–5–1 and core 4–13–3–1 with the high-pressure mercury injection pore throat distribution test results of their parallel samples, the conversion of T2 value to pore radius can be achieved. Furthermore, the pore structure of the shale core can be determined based on the T2 spectrum of fluid signals in the pore space, achieving quantitative identification of porosity and movable fluids corresponding to different sizes (< 0.0l μm micropores; 0.01–0.1 μm small pores; 0.1–1.0 μm medium pores; > 1.0 μm large pores) of pores before and after immersion in external fluids. The relationship between the obtained pore distribution and relaxation time is shown in Fig. 2.

Fig. 1
figure 1

T2 spectrum of pure shale samples (core 24–5–1–1 and core 4–13–3–1) under dry, saturated formation water, and variable viscosity slick water conditions

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Fig. 2
figure 2

Pore distribution characteristics of pure shale samples (core 24–5–1–1 and core 4–13–3–1) in their initial state and after soaking in variable viscosity slick water

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Figure 2 shows the pore distribution characteristics of pure shale samples (core 24–5–1–1 and core 4–13–3–1) in their initial state and after soaking in slick water. It can be found from Fig. 2 that (a) the total porosity of pure shale decreases after the action of slick water. The total porosity of core 24–5–1–1 and core 4–13–3–1 after saturated formation water is 3.97% and 3.71%, respectively. The total porosity after saturation with variable viscosity slick water is 3.89% and 3.66%, respectively, reducing by 0.08% and 0.05%. (b) The decrease in total porosity refers to a decrease in the porosity of the fluid, which are 2.03% and 1.24%, respectively. (c) After the interaction between pure shale and variable viscosity slick water, the number of small pores increases, while the porosity of microscale and nanoscale pores, mesopores, and macropores slightly decreases.

Table 2 presents the quantitative characterization results of pore distribution in core 24–5–1–1 and core 4–13–3–1 after soaking in variable viscosity slick water. It can be seen from Table 2 that (a) the interaction between pure shale and slick water leads to an increase in nanoporous porosity, while the porosity of small, medium, and large pores decreases. (b) After saturation with formation water, the mesoporous porosity of core 24–5–1–1 and core 4–13–3–1 are 0.12% and 0.23%, respectively; After saturation with variable viscosity slick water, the mesoporous porosity are 0.12% and 0.20% respectively, and the change values of mesoporous porosity are 0% and − 0.03%, with a change rate of − 14.48% to 0.83%. (c) After saturation with formation water, the macroporous porosity of core 24–5–1–1 and core 4–13–3–1 are 0.47% and 0.11%, respectively; After saturation with variable viscosity slick water, the macropore porosity are 0.39% and 0.09% respectively, and the variation values of macropore porosity are − 0.08% and − 0.02%, with a decrease of 17.66 to 17.79%. (d) Core 24–5–1–1 and core 4–13–3–1 showed a decrease of 0.02% and 0.02% in micropores and small pores, respectively, after the action of slick water. The decrease in micropores is 0.65% to 0.95%, while the increase in small pores is 1.73% to 3.40%.

Table 2 The distribution of pore throats of different sizes in core 24–5–1–1 and core 4–13–3–1 before and after soaking in variable viscosity slick water
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Table 3 summarizes the evaluation results of the sensitivity of the pore structure of core 24–5–1–1 and core 4–13–3–1 to slick water. It can be found from Table 3 that slick water is not sensitive to total porosity, and is not sensitive to microsclae and nanoscale pores and small pores, causing weak damage to mesopores and large pores. In summary, the research results indicate that slick water is not sensitive to the total porosity of pure shale, and is not sensitive to microscale and nanoscale pores and small pores. It has a slight impact on porosity, causing weak damage to mesopores and large pores, leading to a significant decrease in porosity.

Table 3 Evaluation results of the sensitivity of pore structures in core 24–5–1–1 and core 4–13–3–1 to variable viscosity slick water
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4.2 Sensitivity of pure shale pore structure to backflow fluid.

The influence of backflow fluid on the pore structure of pure shale is studied using core 40–3–2 and core 4–13–6–2. Figure 3 shows the T2 spectrum of pure shale under dry samples, saturated formation water, and backflow fluid conditions. As mentioned earlier, by comparing the T2 spectrum of fluid signals in the pore spaces of core 40–3–2 and core 4–13–6–2 with the high-pressure mercury injection pore throat distribution test results of their parallel samples, the conversion of T2 value to pore radius can be achieved. Furthermore, the pore structure of the shale core can be determined based on the T2 spectrum of fluid signals in the pore space, achieving quantitative identification of porosity and movable fluids corresponding to different sizes (< 0.0l μm micropores; 0.01–0.1 μm small pores; 0.1–1.0 μm medium pores; > 1.0 μm large pores) of pores before and after immersion in external fluids. The relationship between the obtained pore distribution and relaxation time is shown in Fig. 4.

Fig. 3
figure 3

T2 spectrum of pure shale samples (core 40–3–2 and core 4–13–6–2) under dry, saturated formation water, and backflow fluid conditions

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Fig. 4
figure 4

Pore distribution characteristics of pure shale samples (core 40–3–2 and core 4–13–6–2) in their initial state and after soaking in backflow fluid

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Figure 4 shows pore distribution characteristics of pure shale samples (core 40–3–2 and core 4–13–6–2) in their initial state and after soaking in backflow fluid. As shown in Fig. 4, (a) the total porosity of pure shale increases after saturated with backflow fluid. The total porosity of core 40–3–2 and core 4–13–6–2 after saturated with formation water are 4.16% and 3.60%, respectively. (b) The total porosity after saturated with backflow fluid are 4.22% and 3.66%, respectively, with an increase of 0.06% and 0.06%. (c) The increase in total porosity refers to an increase in the porosity of the fluid, which are 1.85% and 1.43%, respectively.

Table 4 presents the quantitative characterization results of pore distribution in core 40–3–2 and core 40–13–6–2 after soaking in backflow fluid. According to Table 4, it can be seen that (a) after the interaction of pure shale and backflow fluid, the macroscale pore porosity increases, while the microscale and nanoscale pore, small pore, and mesoscale pore porosity slightly decrease. (b) The macroscale pore porosity of core 40–3–2 and core 4–13–6–2 saturated with formation water are 0.71% and 0.03%, respectively. (c) The macroscale pore porosity after saturated with backflow fluid are 0.79% and 0.03%, respectively. The variation values of macroscale pore porosity are 0.08% and 0.01%, with an increase of 11.29–22.99%. (d) The microscale pore porosity of core 24–5–1–1 and core 4–13–3–1 increased by 0.02–0.07% after saturation with slick water; The porosity of small pores and mesoscale pores decreased by 0.02–0% and 0–0.02%, respectively. The decrease in microscale pore is 0.68–3.61%, the decrease in small pore is 0.21–4.42%, and the decrease in mesoscale pore is 1.80–3.25%.

Table 4 The distribution of pore throats of different sizes in core 24–5–1–1 and core 4–13–3–1 before and after soaking in backflow fluid
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Table 5 summarizes the evaluation results of the sensitivity of the pore structure of cores 40–3–2 and 4–13–6–2 to backflow fluids. According to Table 5, it can be seen that the backflow fluid is not sensitive to the total porosity, is not sensitive to microscale, nanoscale, small, and medium pores, and has weak improvement on large pores. In summary, the results of this study indicate that the total porosity of pure shale is not sensitive to backflow fluid, while microscale and nanoscale pores and small and medium pores are not sensitive to backflow fluids, with slight changes in porosity; backflow fluid has a weak improvement effect on macroscale pores, leading to a significant increase in porosity.

Table 5 Evaluation results of the sensitivity of pore structures in core 40–3–2 and core 4–13–6–2 to backflow fluid
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4.3 Sensitivity of carbonaceous shale pore structure to variable viscosity slick water.

The influence of variable viscosity slick water on the pore structure of carbonaceous shale is studied using core 3–4–2–2 and core 44–3–1. Figure 5 shows the T2 spectrum of carbonaceous shale under dry samples, saturated formation water, and variable viscosity slick water conditions. As mentioned earlier, by comparing the T2 spectrum of fluid signals in the pore spaces of core 3–4–2–2 and core 44–3–1 with the high-pressure mercury injection pore throat distribution test results of their parallel samples, the conversion of T2 value to pore radius can be achieved. Furthermore, the pore structure of the shale core can be determined based on the T2 spectrum of fluid signals in the pore space, achieving quantitative identification of porosity and movable fluids corresponding to different sizes (< 0.0l μm micropores; 0.01–0.1 μm small pores; 0.1–1.0 μm medium pores; > 1.0 μm large pores) of pores before and after immersion in external fluids. The relationship between the obtained pore distribution and relaxation time is shown in Fig. 6.

Fig. 5
figure 5

T2 spectrum of carbonaceous shale samples (core 3–4–2–2 and core 44–3–1) under dry, saturated formation water, and variable viscosity slick water conditions

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Fig. 6
figure 6

Pore distribution characteristics of carbonaceous shale samples (core 3–4–2–2 and core 44–3–1) in their initial state and after soaking in variable viscosity slick water

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From Fig. 6, it can be seen that the total porosity of carbonaceous shale decreases after saturation with slick water. The total porosity of core 3–4 2–2 and core 44–3–1 after saturation with formation water are 6.85% and 4.14%, respectively; the total porosity after saturation with slick water are 6.28% and 3.90%, respectively, reducing by 0.57% and 0.24%. The decrease in total porosity refers to a decrease in the porosity of the fluid, which are 8.46% and 5.71%, respectively. After the interaction of carbonaceous shale with slick water, the porosity of microscale and nanoscale pore and macroscale pore decreases, while the porosity of small pore and mesoscale pore increases.

Table 6 presents the quantitative characterization results of pore distribution in core 3–4 2–2 and core 44–3–1 after soaking in slick water. According to Table 6, it can be seen that the interaction between carbonaceous shale and slick water leads to a decrease in microscale and nanoscale pore porosity, while the porosity of small, medium, and large pores increases. After saturation with formation water, the macroscale pore porosities of core 3–4 and core 44–3–1 are 0.63% and 0.18%, respectively; after saturation with slick water, the macroscale pore porosity are 0.10% and 0.01% respectively, and the variation values of macroscale pore porosity are − 0.53% and − 0.17%, with a decrease of 84.75–95.16%. Core 3–4 2–2 and core 44–3–1 showed a decrease of 0.20–0.23% in microscale pore porosity after saturation with slick water, while the microscale and mesoscale pores increased by 0.10% − 0.16% and 0.03%, respectively. The microscale pore decreased by 4.43–5.59%, the microscale pore increased by 7.81–12.53%, and the mesoscale pore increased by 3.95–5.52%.

Table 6 The distribution of pore throats of different sizes in core 3–4 2–2 and core 44–3–1 before and after soaking in variable viscosity slick water
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Table 7 summarizes the evaluation results of the sensitivity of the pore structure of core 3–4–2–2 and core 44–3–1. According to Table 7, slick water is not sensitive to total porosity, and is not sensitive to microscale and nanoscale pores and small pores, causing weak damage in mesoscale pores and large pores. In summary, the results of this study indicate that slick water is not sensitive to the total porosity of carbonaceous shale, and is not sensitive to microscale and nanoscale pores and small pores, with slight changes in porosity; slick water causes weak damage to mesoscale and macroscale pores, with a significant decrease in porosity.

Table 7 Evaluation results of the sensitivity of pore structures in core 3–4 2–2 and core 44–3–1 to variable viscosity slick water
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4.4 Sensitivity of carbonaceous shale pore structure to backflow fluid.

The influence of backflow fluid on the pore structure of carbonaceous shale is studied using core 3–4–2–1 and core 44–4–2. Figure 7 shows the T2 spectrum of carbonaceous shale under dry samples, saturated formation water, and backflow fluid conditions. As mentioned earlier, by comparing the T2 spectrum of fluid signals in the pore spaces of core 3–4–2–1 and core 44–4–2 with the high-pressure mercury injection pore throat distribution test results of their parallel samples, the conversion of T2 value to pore radius can be achieved. Furthermore, the pore structure of the shale core can be determined based on the T2 spectrum of fluid signals in the pore space, achieving quantitative identification of porosity and movable fluids corresponding to different sizes (< 0.0l μm micropores; 0.01–0.1 μm small pores; 0.1–1.0 μm medium pores; > 1.0 μm large pores) of pores before and after immersion in external fluids. The relationship between the obtained pore distribution and relaxation time is shown in Fig. 8.

Fig. 7
figure 7

T2 spectrum of carbonaceous shale samples (core 3–4–2–1 and core 44–4–2) under dry, saturated formation water, and backflow fluid conditions

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Fig. 8
figure 8

Pore distribution characteristics of carbonaceous shale samples (core 3–4–2–1 and core 44–4–2) in their initial state and after soaking in backflow fluid

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As shown in Fig. 8, the total porosity of carbonaceous shale increases after saturation with backflow fluid. The total porosity of core 3–4 2–1 and core 44 4–2 saturattion with formation water are 5.70% and 4.10%, respectively. After saturation with backflow fluid, the total porosity are 5.91% and 4.16%, respectively, increasing by 0.21% and 0.06%. The increase in total porosity refers to an increase in the porosity of the fluid, which are 3.78% and 1.54%, respectively.

Table 8 presents the quantitative characterization results of pore distribution in cores 3–4 2–1 and 44 4–2 after immersion in backflow fluid. According to Table 8, it can be seen that after the interaction between carbonaceous shale and backflow fluid, the number of mesoscale and macroscale pores increases, while the number of microscale and nanoscale pores slightly decreases. The number of small pores changes, while the porosity of macroscale pore increases. After saturation with formation water, the macroscale pore porosity of core 3–4 2–1 and core 44 4–2 are 0.23% and 0.15%, respectively; after saturation with backflow fluid, the macroscale pore porosity are 0.34% and 0.17% respectively, and the variation values of macroscale pore porosity are 0.11% and 0.02%, with an increase of 14.45–49.16%. After saturation with backflow fluid, the microscale pore porosity of core 3–4 2–1 and core 44 4–2 decreased by 0–0.02%, the small pore porosity changed by − 0.07–0.03%, the mesoscale pore porosity increased by 0.02–0.17%, the microscale pore decreased by 0.07–0.40%, the small pore changed by − 6.61–46.59%, and the mesoscale pore increased by 22.43–24.86%.

Table 8 The distribution of pore throats of different sizes in core 3–4–2–1 and core 44–4–2 before and after soaking in backflow fluid
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Table 9 summarizes the evaluation results of the sensitivity of the pore structure of core 3–4–2–1 and core 44–4–2 to backflow fluid. According to Table 9, it can be seen that the backflow fluid is insensitive to the total porosity of carbonaceous shale, weakly harms microscale and nanoscale pores with moderate to weak improvement, and weakly improves small/medium/large pores with moderate to weak improvement. In summary, the results of this study indicate that the backflow fluid is not sensitive to the total porosity of carbonaceous shale, but has weak damage to microscale and nanoscale pores with moderate improvement, and weak to moderate improvement on small pores, mesoscale pore, and macroscale pore.

Table 9 Evaluation results of the sensitivity of pore structures in core 3–4–2–1 and core 44–4–2 to backflow fluid
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5 Conclusions

In this paper, firstly, taking pure shale as the research object, the influence mechanism of slick water and backflow fluid on the pore throat structure of pure shale is explored. Then, taking carbonaceous shale as the research object, the mechanism of the influence of slick water and backflow fluid on the pore throat structure of carbonaceous shale is analyzed. Finally, a comparative analysis and summary are conducted on the sensitivity of different types of shale to external fluids. Key findings are summarized below:

  1. (a)

    Based on the sensitivity test results of foreign fluids on different types of shale, it was found that slick water has a harmful effect on the total porosity of different types of shale. The change rate is manifested as carbonaceous shale (− 7.1%) > pure shale (− 1.6%).

  2. (b)

    For slick water, the decrease in macropores is the largest, followed by mesopores and micro/nano pores. The average reduction in macropores and micro/nano pores of carbonaceous shale is 90.0% and 5.0%, while the average reduction in macropores and mesopores of pure shale is 17.7% and 6.8%.

  3. (c)

    After the action of backflow fluid, the total porosity of different types of shale is not sensitive. The rate of change satisfies: carbonaceous shale (+ 2.7%) > pure shale (+ 1.6%). The maximum increase is in large pore.

  4. (d)

    For backflow fluid, the average increase in macroscale pore, mesoscale pore, and small pore of carbonaceous shale are 31.8%, 23.6%, 20.2%, respectively; the average increase in macroscale pore of pure shale is 17.1%.