Influence of Hydration on Shale Reservoirs: A Case Study of Gulong Shale Oil

Abstract

In the process of the exploration and development of shale oil, the influence of hydration on shale reservoirs is complex, as it can not only improve porosity and permeability, but also lead to reservoir instability. At present, there is a lack of systematic understanding of the influence of hydration on the physical and chemical properties of shale oil reservoirs. Therefore, in this study, taking the Gulong shale oil reservoir in Songliao Basin as the research object, X-ray diffraction mineral composition analysis, electron microscope scanning, and micro-CT scanning were used to study the micro–macro-changes in shale caused by hydration, and the effects of different fracturing fluids on hydration were evaluated. The results show the following: (1) Hydration increases the porosity and permeability of Gulong shale through clay dispersion and dissolution pore formation, though these transient effects may compromise long-term reservoir stability due to pore-throat clogging. (2) Prolonged hydration significantly enhanced pore structure complexity, with tortuosity increasing by 64.7% (from 2.19 to 3.60) and the fractal dimension rising by 7.5% (from 1.99 to 2.14) with hydration time, and the proportion of larger pores (50–100 μm) increased significantly. (3) Hydration leads to crack propagation and new cracks, and the intersection of cracks reduces the core strength, which may eventually lead to macroscopic damage. (4) The influence of different fracturing fluids on the hydration reaction is obviously different. The higher the concentration, the stronger the hydration effect. Distilled water helps to increase porosity and permeability, but long-term effects may affect reservoir stability. The results of this paper reveal the changes in micro- and macro-characteristics of shale oil reservoirs under hydration, which is of great significance for analyzing the mechanism of hydration and provides theoretical support for improving shale oil recovery.

1. Introduction

With the gradual deepening of oil exploration and development of research into deep and complex strata, the stability of shale reservoirs has become increasingly prominent. Shale reservoirs often contain a large number of clay minerals, especially water-sensitive minerals such as montmorillonite and illite [1,2,3]. These minerals will undergo physical and chemical reactions such as expansion and dispersion under hydration, thus affecting the pore structure and physical and mechanical properties of the reservoir [4,5,6]. In the development of shale reservoirs, hydration may lead to changes in pore structure, which in turn affects the seepage capacity and strength of the reservoir [7,8]. In an environment with a high water content, hydration will cause the expansion of clay minerals, resulting in significant changes in porosity and permeability, especially affecting the stability and strength of the reservoir [9,10]. Therefore, the study of the effects of hydration on shale reservoirs not only helps to understand the physical and chemical properties of shale, but also provides a theoretical basis for further improving drilling efficiency and enhancing reservoir reconstruction.

With the extension of hydration time, the pore structure of shale may become more complex, and the porosity and permeability may increase, but this increase does not mean that the stability of the reservoir is improved [11,12]. On the contrary, hydration may lead to a decrease in reservoir strength, which in turn affects the safety and effectiveness of drilling and fracturing operations [13,14,15]. Therefore, it is of great theoretical value and practical significance to explore the specific influence mechanism of hydration on shale reservoirs and reveal its influence on reservoirs’ physical properties and mechanical behavior. Gulong shale is a typical continental shale with high clay mineral content and a complex pore structure, which represent the characteristics of typical shale oil reservoirs in China [16,17,18]. Although some progress has been made in the exploration and development of Gulong shale in recent years, due to the influence of hydration, the problems of shale gas wellbore instability and unsatisfactory fracturing effects are still unexplored [6,19]. Therefore, studying the mechanism of hydration of Gulong shale and revealing its influence on reservoirs’ physical properties and seepage characteristics is an important issue to be solved urgently in the field of shale gas development.

In this study, Gulong shale was selected as a representative shale reservoir for investigation. The effects of hydration on the physical and chemical properties and pore structure of the Gulong shale reservoir are systematically studied by means of X-ray diffraction analysis, micro-CT scanning, Electron microscope scanning analysis, and pulse porosity–permeability measurement experiment. Through a series of analytical characterization techniques, the effects of hydration on clay mineral expansion, porosity and permeability changes, and fracture propagation are discussed, and the evolution process of reservoir pore structure under different hydration times and different hydration strengths is studied.

2. Experimental Samples and Method

2.1. Experimental Samples

The samples used in this paper (Figure 1) were selected from Gulong shale in the first section of the Qingshankou Formation in the Songliao Basin. The total organic carbon (TOC) and X-ray diffraction analysis results are shown in

Table 1. Integrated analysis of mineralogical composition and TOC content in rock samples.

Number	TOC	Mineral Content (%)					Relative Content of Clay Mineral (%)
		Quartz	Potash Feldspar	Plagioclase	Pyrite	Clay Mineral	Mixed-Layer Illite	Illite	Chlorite
S-1-6	2.33	30.2	0.6	11.4	7.3	50.5	35	44	21
S-1-15	2.24	33.1	0.8	15.3	8.2	42.6	25	32	43
S-1-1	2.21	35.7	0.6	17.5	4.9	41.3	30	42	28

. The TOC content of the three samples ranges from 2.21% to 2.33%. The brittle minerals of Gulong shale are mainly quartz and plagioclase, with quartz content of 30.2%–35.7% and plagioclase content of 11.4%–17.5%. The high content of brittle minerals provides favorable conditions for the formation of cracks, thus weakening the pressure-bearing capacity of the formation, which is one of the potential factors influencing wellbore instability. In addition, the content of clay minerals is as high as 40%, comprising mainly illite (32%–44%), followed by an illite/smectite mixed layer (25%–35%), which contains a small amount of chlorite (21%–43%).

2.2. Experimental Instruments and Principles

2.2.1. X-Ray Diffraction Test

The Japanese Rigaku high-resolution SmartLab X-ray diffractometer (Japanese Rigaku, Tokyo, Japan) was used to perform X-ray diffraction analysis on the samples, analyze their diffraction patterns, and obtain information such as the composition of the material and the structure or morphology of the atoms or molecules inside the material. The diffraction characteristics of different crystal structures can be superimposed to determine the diffraction patterns of multiphase samples. By comparing the observed patterns with those in the powder diffraction database (PDF), the phase can be determined and the relative content of each phase can be estimated according to the diffraction intensity. X-ray diffraction analysis is conducted according to the procedures described in previously published studies [20,21].

2.2.2. Micron CT Scanning Test

A Domestic micro–nano dual-ray tube core CT scanning system is used to penetrate the core sample through X-ray, and the three-dimensional pore structure of the core is reconstructed through rotation and multi-angle projection images. This technology does not need to destroy the samples, and can quickly and non-destructively display the microscopic pore throat characteristics of reservoir rocks, and quantitatively analyze their geometry, size, connectivity, and distribution. The CT image is based on X-ray attenuation information, and the gray value is related to the core density, which can directly reflect the pore structure. A micron CT scanning test is conducted according to the procedures described in previously published studies [22]. Instrument Parameters: (1) Sample Parameters—1–260 mm (sample diameter). (2) Voltage—micron tube: 0–240 kV; nanotube: 0–180 kV. (3) Pixel Size—micron tube: 20–122 µm; nanotube: 0.6–20 µm.

2.2.3. Scanning Electron Microscopy Test

The electron microscope scanning analysis uses a finely focused electron beam that is stationary or performs grating scanning on the surface of the sample to bombard the surface of the sample so that it produces various signals (secondary electrons, backscattered electrons, Auger electrons, characteristic X-rays, photons of different energies, etc.), and the solid material is analyzed by using an electromagnetic lens system. The scanning electron microscopy test is conducted according to the procedures described in previously published studies [23,24]. The experimental parameters are as follows: sample dimensions—flake-shaped samples with diameters less than 25 mm; pixel size—0.9 nm–800 nm; accelerating voltage—500 V–30 kV; beam current—1 pA–100 nA; cutting precision—10 nm.

2.3. Experimental Method

2.3.1. X-Ray Diffraction Analysis

Shale is primarily composed of matrix pores and bedding fractures, and is rich in a variety of clay minerals. Chlorite has lipophilicity, its crystal structure is stable, and it is less affected by hydration. Kaolinite exhibits low hydrophilicity and negligible swelling capacity, whereas illite and montmorillonite represent the most expansive phyllosilicates upon hydration. Therefore, in this experiment, Gulong shale, with a high content of illite and illite–montmorillonite mixed-layer minerals was selected. In order to analyze the influence of different fracturing fluids on clay minerals in shale reservoirs, an X-ray diffractometer was used to test and analyze the content of clay mineral components. (1) Three Gulong shale cores were selected, each of which was divided into four slices, and the test samples were ground to about 0. 15 mm. (2) The shale samples were immersed in distilled water and different types of fracturing fluid systems (No.1 friction reducer: polyacrylamide-based system; No.2 friction reducer: guar gum-based system) with varying concentrations (0.1%, 0.3%) in a constant-temperature chamber. After soaking for 1, 3, 5, and 7 days (simulated field frac fluid residence time), the shale slices were carefully wiped dry and subsequently subjected to X-ray diffraction analysis. Permeability and porosity measurements were conducted before and after the treatment.

2.3.2. Micron CT Scanning Analysis

(1) A piece of Gulong shale was selected and vacuumized with a vacuum pump for 12 h, and then immersed in a beaker filled with distilled water. (2) After soaking for 0 days, 1 day, and 7 days, the samples were taken out, dried, and placed in the micro–nano dual-ray tube core CT scanning system for CT scanning analysis.

2.3.3. Scanning Electron Microscopy Analysis

(1) Three Gulong shale core slices were selected, and the surface of the slices was polished by argon ion polishing and sprayed with carbon film. (2) The treated shale sections were placed in a resistance-reducing agent solution containing distilled water and different types of resistance-reducing agent (No. 1 resistance-reducing agent is a polyacrylamide system, and No. 2 resistance-reducing agent is a guar gum system). After soaking in the incubator for 0 days and 7 days, the shale sections were wiped clean and subjected to electron microscope scanning experiments.

3. Result

3.1. Effect of Hydration on Microstructure and Physical Parameters of Shale

3.1.1. The Differences in Porosity and Permeability Before and After Hydration

The test specimens were submerged in distilled water and maintained at a standard temperature (25 °C) and pressure (1 atm) for a 7-day hydration period. The porosity and permeability of three Gulong shale cores were measured by a pulsed porosity and permeability instrument, following the procedures described in previously published studies [25,26]. The porosity before hydration was between 0. 833% and 1.80%, and the porosity after hydration was between 0.915% and 2.37% (Figure 2a). The permeability before hydration was between 0.001 mD and 0.005 mD, and the permeability after hydration was between 0.0015 mD and 0.0076 mD (Figure 2b). Hydration will increase shale porosity and permeability, and improve the seepage channel of the reservoir to a certain extent. Xue et al. [9] also supported that the porosity and permeability parameters of rock samples increased after hydration, and the cracks that formed after hydration contributed greatly to the increase in the permeability of the rock samples.

3.1.2. Comparison of Shale Hydration Based on Micron CT Scan

The pore structure of shale reservoirs is complex, so the fractal dimension is often used to evaluate the complexity and heterogeneity of shale reservoirs [27,28]. The large fractal dimension of shale indicates that the complexity of its pore structure is high, and the roughness of its pore surface and the irregularity of its shape are high. Tortuosity, an important parameter affecting the permeability of porous media, characterizes the bending degree of pores with different sizes in porous media [29,30]. Figure 3 shows the pore identification model of the S-1-6 core before and after hydration. From Figure 1, it can be seen that the pore volume after hydration increases significantly, and the porosity of the S-1-6 core decreases first and then increases; the initial clay content is 1.87%, and it is reduced to 1.25% after 1 day, indicating that the early clay minerals expand and disintegrate after encountering water, which will fill up the small pores and cause the pore volume to decrease. The pore size increased significantly after 7 days of hydration, indicating that over time, the hydration of hydrophilic mineral particles increased and the cementation strength decreased, resulting in the loosening and shedding of mineral particles and the generation of dissolution pores, which eventually increased the pore volume. Figure 4 is a model of a shale stick before and after hydration. From Figure 4, it can be seen that the flow path of fluid in shale becomes more tortuous, and the tortuosity increases from 2.186 to 3.60. Figure 4 also shows that with the strengthening of hydration, a small number of dissolution pores are produced in shale, and these tiny dissolution pores make the pore structure of shale more complex. Figure 5 illustrates shale segmentation before and after hydration. It can be seen from Figure 5 that with an increase in hydration time, crack propagation and derivation occur on the surface of shale, and the fractal dimension increases (from 1.99 to 2.14). Figure 5 also shows that after hydration, the micropores and cracks in shale increase, and the fractal dimension increases, which makes the pore structure of shale more complex. These cracks intersect and connect with each other, reducing the strength of the core and causing macroscopic damage to the rock. Figure 6 shows the pore size distribution after hydration for different times. It can be seen from Figure 6 that the proportion of medium and large pores in shale increases gradually, and the growth rate of pores with sizes in the range of 100–150 μm is the largest, indicating that with an increase in hydration time, the formation of dissolution pores contributes to an increase in the proportion of macropores within the pore system. Previous studies by Yang [31] and Shi et al. [32] have demonstrated, through micro-CT and field emission scanning electron microscopy (FE-SEM) analyses, that water–rock interactions can induce the development of new micropores and microfractures in shale formations. This also shows that under the action of hydration with distilled water, Gulong shale will undergo structural damage, resulting in a decrease in the mechanical strength of the reservoir, and with the extension of soaking time, the greater the degree of damage, the greater the decrease in the rock’s mechanical strength.

3.2. Study on the Influence of Fracturing Fluid Type on Shale Hydration

3.2.1. Effect of Fracturing Fluid Type on Permeability

Table 2. Changes in porosity and permeability before and after hydration of different fracturing fluids.

Experimental Scheme	Permeability (Before Hydration)/mD	Permeability (After Hydration)/mD	Rate of Change/%	Porosity (Before Hydration)/%	Porosity (After Hydration)/%	Rate of Change/%
1-A	0.005	0.0076	55.12	1.80	2.17	20.56
1-B	0.0051	0.00422	−20.85	1.81	1.71	−5.81
1-C	0.0055	0.004175	−31.74	1.82	1.55	−17.65
1-D	0.0053	0.004164	−27.28	1.80	1.58	−13.64
2-A	0.003	0.00482	60.58	0.95	1.14	20.32
2-B	0.0032	0.00268	−19.40	0.96	0.86	−11.11
2-C	0.0033	0.002405	−37.21	0.95	0.82	−16.65
2-D	0.0038	0.002944	−29.08	0.97	0.85	−12.64
3-A	0.001	0.00154	54.32	0.83	0.97	15.85
3-B	0.0011	0.00089	−23.60	0.82	0.73	−12.11
3-C	0.0013	0.000955	−36.13	0.82	0.69	−18.65
3-D	0.0012	0.000956	−25.52	0.81	0.71	−14.64

Scheme coding definitions: sample number-soaking solution (1: S-1-6; 2: S-1-15; 3: S-1-1)—A: distilled water; B: 0.1% No. 1 drag-reducing agent (polyacrylamide system); C: 0.3% No. 1 drag-reducing agent (polyacrylamide system); D: 0.1% No. 2 drag-reducing agent (guar gum system).

shows the differences in porosity and permeability before and after hydration under different types of fracturing fluid conditions. It can be seen from the table that the fracturing fluid causes a decrease in permeability and porosity due to retention and adsorption of the rock pore throat surface. With an increase in concentration, the greater the decrease, the more serious the damage. At the same concentration, the damage degree of the guar gum system is greater than that of polyacrylamide system, and distilled water will increase the porosity and permeability of the reservoir.

3.2.2. Comparison of Shale Hydration Based on X-Ray Diffraction

Table 3. Clay mineral content after soaking for 0 days.

Number	Experimental Scheme	Relative Content of Clay Minerals (%)			Ratio of Mixed Layer (%S)
		Mixed-Layer Illite	Illite	Chlorite	Mixed-Layer Illite
1	1-0-A	34	41	25	10
2	1-0-B	33	40	24	10
3	1-0-C	32	39	23	10
4	1-0-D	33	40	22	10
5	2-0-A	24	33	43	10
6	2-0-B	24	31	45	10
7	2-0-C	23	34	43	10
8	2-0-D	23	32	45	10
9	3-0-A	33	45	22	10
10	3-0-B	30	42	28	10
11	3-0-C	28	43	29	10
12	3-0-D	32	43	25	10

Scheme coding definitions: sample number-soaking solution (1:S-1-6; 2:S-1-15; 3:S-1-1)—A: distilled water; B; 0.1% No. 1 drag-reducing agent (polyacrylamide system); C: 0.3% No. 1 drag-reducing agent (polyacrylamide system); D: 0.1% No. 2 drag-reducing agent (guar gum system).

and

Table 4. Clay mineral content after soaking for 7 days.

Number	Experimental Scheme	Relative Content of Clay Minerals (%)			Ratio of Mixed Layer (%S)
		Mixed-Layer Illite	Illite	Chlorite	Mixed-Layer Illite
1	1-0-A	35	40	25	10
2	1-0-B	35	39	26	10
3	1-0-C	38	37	25	10
4	1-0-D	36	41	23	10
5	2-0-A	26	31	43	10
6	2-0-B	27	29	44	10
7	2-0-C	26	30	44	10
8	2-0-D	29	29	42	10
9	3-0-A	35	42	23	10
10	3-0-B	32	43	25	10
11	3-0-C	29	42	29	10
12	3-0-D	30	41	29	10

Scheme coding definitions: sample number-soaking solution—A: distilled water; B: 0.1% No. 1 drag-reducing agent (polyacrylamide system); C: 0. 3% No. 1 drag-reducing agent (polyacrylamide system); D: 0.1% No. 2 drag-reducing agent (guar gum system).

illustrate the differences in clay mineral content before and after shale hydration under different types of fracturing fluid conditions. As shown in Table 3 and Table 4, there is little difference in the types of clay minerals before and after hydration with different types of fracturing fluids. The influence of different fracturing fluids on the reservoir is mainly due to the retention of micro-pore throats and adsorbed rock pore throat surfaces.

3.2.3. Comparison of Shale Hydration Based on Electron Microscopy Scanning Experiments

By comparing the shale slices of S-1-6 shale before and after hydration with different fracturing fluids (Figure 7), it was found that the shale samples contained more clay minerals before being soaked in distilled water. In addition, the edges of mineral particles were obvious, and there were large intergranular pores in the form of slits. When the shale sample was soaked for 7 days, it was found that the mineral particles fell off and dissolved, the tiny pores were further dissolved, and the pore radius increased. After soaking in the polyacrylamide system fracturing fluid for 7 days (Figure 8), it was found that the clay minerals had expanded significantly, and the edges of the particles were passivated. There was loosening and shedding of the particles, and there may have been clogging of the pores. After S-1-6 shale was soaked in guar gum fracturing fluid for 7 days (Figure 9), it was found that the clay minerals expanded significantly, and there was a phenomenon of fracturing fluid retention. A layer of hydration film was added on the surface of the clay minerals, and the number of tiny pores was reduced. In summary, hydration significantly affects the seepage capacity and stability of the reservoir by changing the pore structure and physical and mechanical properties of the shale. In the process of shale oil and gas development, reasonable formulas and construction parameters for fracturing fluid should be selected according to the hydration characteristics, so as to minimize the negative impact of hydration on reservoir stability and provide a scientific basis for shale reservoir development [33,34].

4. Discussion

In this study, the changes in reservoirs’ physical properties under hydration and influence mechanism of hydration on Gulong shale in the Songliao Basin were systematically evaluated by means of CT scanning, X diffraction, micron CT scanning and electron microscope analysis. The results show that hydration has a significant effect on the pore structure and permeability of shale reservoirs. The expansion effect of clay minerals and the properties of fracturing fluid components are the main reasons for the weakening of pore connectivity and the change in permeability. In addition, the three-dimensional visualization results of micro-CT scanning further reveal the dynamic evolution process of reservoir pore structure complexity in response to hydration, which provides a deeper understanding the mechanism of changes in shale reservoir microstructure. In this study, the influence of fracturing fluid type on the hydration of the Gulong shale oil reservoir was quantitatively and qualitatively analyzed by X-ray diffraction mineral composition analysis and the electron microscope scanning method for the first time, which provided an important reference for reservoir evaluation and development optimization.

Although this study reveals the important influence of hydration on reservoir reconstruction, it is found that the hydration of shale for a long enough time will produce more positive effects, such as micro-fracture propagation and dissolution pore generation. However, there are still some differences between the experimental conditions and the actual formation environment. In field operation, it is also possible that the confining pressure in the high-pressure environment inhibits the cracking and further expansion of the original micro-cracks, resulting in the closure of micro-cracks rather than their expansion. The complex ion environment in the actual formation may have a more complex effect on the expansion behavior of minerals and the change in pore structure. Therefore, the influence of shale reservoir hydration in a real environment needs further exploration. In addition, due to the limited number of samples, the regional applicability of our research results needs to be further verified. Therefore, future research should be carried out on the following topics: first, the regulatory effects of different chemical environments on hydration should be explored by introducing experiments that simulate complex formation conditions; second, researchers should expand the scope of research samples and evaluate the universality of hydration under different geological backgrounds; thirdly, the mechanisms of different chemical additives in fracturing fluid should be further studied to provide more scientific guidance for reservoir reconstruction.

5. Conclusions

(1) The expansion and dispersion of clay minerals and the generation of dissolution pores caused by hydration are the main reasons for the increase in the porosity and permeability of the reservoir, but also reduce its stability.

(2) The analysis of the pore identification model shows that hydration enhances the complexity and heterogeneity of shale pore structure. Hydration makes the fluid flow path more tortuous. The tortuosity and fractal dimension increase with an increase in hydration time. The tortuosity increases from 2.186 to 3.60, and the fractal dimension increases from 1.99 to 2.14. Dissolution causes an increase in the proportion of medium and large pores, especially in the range of 100–150 μm.

(3) Hydration induces the propagation and derivation of cracks on the surface of shale, and the intersection of cracks reduces the strength of the core, which leads to macroscopic damage. Scanning electron microscopy showed that the hydration of clay minerals made the edges of mineral particles loosen and fall off, resulting in dissolution, thus forming larger intergranular pores.

(4) The fracturing fluid of the guar gum system causes more serious damage to the reservoir than that of the polyacrylamide system, and the higher the concentration, the greater the decrease in porosity and permeability. Distilled water promotes a relative increase in porosity and permeability, but its long-term effect may lead to instability of the reservoir structure.