The shale fracture permeability is critical in determining gas production and deep CO2 sequestration performance. Moreover, how shale fracture permeability evolves after interactions with supercritical carbon dioxide (Sc-CO2) should be understood to constrain the shale reservoir permeability and evaluate the long-term sealing ability of shale formations. In this research, we conducted soaking experiments with shale fractures and Sc-CO2 at various times and then measured the shale fracture permeability and hydraulic aperture evolution under different stress states. Additionally, we quantify the chemical compositions, pore characteristics, fracture surface roughness alternation through X-ray diffraction, nuclear magnetic resonance, scanning electron microscope, and optical profilometry techniques. Our results indicate that soaking with Sc-CO2 will dramatically increase the shale fracture permeability and aperture due to the calcite and dolomite dissolution. This free-face dissolution process will remove the mineral particles in the fracture surface, resulting in larger pores, peaks, and valleys in the fracture surfaces. This process may last for seven days, and after that, chemical reactions may terminate, and the rock-Sc-CO2 system turns stable. Our results explain how Sc-CO2 alters the shale fracture permeability through the chemical dissolution of specific minerals from a microscale analysis.

1. Introduction

Shale gas production has boomed during the last decades due to the technological advancements in horizontal drilling and multistage fracturing in Sichuan Basin, China [13]. As the primary technology during shale gas development, hydraulic fracturing is implemented by injecting a large amount of water and sand proppants [46]. Researches indicated that potential drawbacks include massive consumption of water, underground water contamination, and possible fluid injection-induced seismic events [710]. Moreover, the high clay content in shale formation and its chemical reaction with water will induce the swelling phenomenon and induce the permeability enhancement performance not to be satisfied [11]. Thus, some other fracturing fluids have been proposed to replace conventional water-based fracturing fluids, such as nitrogen and supercritical carbon dioxide (Sc-CO2) [12, 13]. Sc-CO2 may be a good choice due to its characteristics of high density and low viscosity under the reservoir conditions, in which the temperature is higher than 31.1°C and the pressure is higher than 7.38 MPa [14]. Recent research also validated that the Sc-CO2 may decrease the shale reservoir breakdown pressure and create complex fracture networks due to its low viscosity property, benefiting shale reservoirs permeability enhancement [1519].

After the Sc-CO2 injection into the shale formation, the shale rock properties may change due to the stress (mechanical) and chemical reactions. The research on the interactions between shale rock and Sc-CO2 is also a hot topic in the oil and gas industry. The experimental results show that the adsorption of Sc-CO2 induces the shale matrix swelling, which alters the mechanical properties of shale [2022]. Moreover, experimental results found that the interactions between shale rock and Sc-CO2 would significantly decrease the mechanical properties of shale rock, including uniaxial compressive strength (UCS), tensile strength, and elastic modulus [2326]. Scholars commonly explain this weakening effect from the aspects of microscale structural alternation [2729]. Experimental results found that the shale’s specific surface area and porosity will increase after the treatment by Sc-CO2 through dissolving the organic matter in the shale [30]. Nuclear magnetic resonance (NMR) measurements with shale from Gippsland Basin, Australia, indicate the pore volume will increase after exposure to Sc-CO2, which results from chemical reactions, including dissolution and precipitation of kaolinite, natrojarosite, silica, and gypsum [31]. Alemu et al. found that the carbonate-rich shale will react with plagioclase and clay minerals, which induce the CO2 sequestration in the shale as the calcite [32]. In situ experiments in Utica shale indicate that CO2 will interact with Kergon and illite-smectite clays in shale, which means that those shale plays have higher CO2 storage capacity [33]. Experiments with Eagle Ford and Mancos shales indicate that quartz content increases after the treatment with Sc-CO2, while clay and carbonate minerals’ contents decrease. Thus, the mineral carbonation trapping could be an effective mechanism for long-term CO2 storage in shale reservoirs [34]. As mentioned above, researchers attempted to analyse the interaction between Sc-CO2 and various kinds of shale from the mechanical aspects. As the main fluid channels for shale gas during the production, fracture permeability plays a vital role in shale gas production, and how the fracture permeability evolves remains poorly understood.

Previous experimental researches found that the fracture permeability may increase or decrease due to various mechanical, chemical, and thermal processes [35, 36]. The fracture permeability may increase through the free-face dissolution, while permeability decrease is observed through the processes such as clay mineral swelling, pressure solution, mechanical compaction, and secondary mineral precipitation [3741]. Thus, a deep understanding of how fracture permeability evolves and the link between fracture permeability and microscale fracture surface alternation will help constrain the permeability evolution of shale fractures due to the Sc-CO2 soak.

This study aims to understand how the shale fracture surface alters and how fracture permeability evolves after the Sc-CO2 soak. We perform a series of fracture permeability measurements after the soak of shale fractures into Sc-CO2 for 1, 3, 5, 7, and 14 days. Analysis techniques, including X-ray diffraction analysis (XRD), surface profilometry scanning, and nuclear magnetic resonance (NMR), are used to understand how the mineralogy, fracture surface roughness, and pore volume distribution change due to the Sc-CO2 soak. Our results provide a deeper understanding of the alternation effect of Sc-CO2 on the shale fracture permeability.

2. Samples and Experimental Method

The experimental study consists of several components: (a) shale samples soaking with Sc-CO2 under the temperature of 50°C and 10 MPa for 1, 3, 5, 7, and 14 days; (b) shale fracture permeability measurement under the effective normal stress ranges from 1 to 20 MPa; (c) XRD tests for mineralogy analysis, NMR tests for shale pore characteristics analysis, and surface profilometry scanning tests for fracture surface roughness analysis.

2.1. Sample Preparation

The shale samples used in this research were collected from Lower Silurian Formation in Sichuan Basin, China, which was also the main shale gas producing area in China. The core samples were firstly drilled from the shale blocks with a diameter of 25.4 mm. Then, the shale samples were cut into a length of 50.8 mm. After that, the rock samples were saw-cut into two halves with a smooth fracture surface and later polished with the abrasive silicon carbide (20 grits, equivalent to 830 μm) to create rough fracture surfaces. The prepared shale samples are shown in Figure 1(a). Our previous research results indicated that this method creates fracture surfaces with similar fracture roughness to the fractures induced by Sc-CO2 fracturing [16]. The mineralogical composition of shale samples is listed in Table 1. The main mineral is quartz, which accounts for 44.13% of total weight. Following that, illite accounts for 23.18% and 19.61% for calcite. Other minor minerals include dolomite and albite, which account for 8.59% and 4.49% separately. Furthermore, we group the minerals into three categories, tectosilicate, carbonate, and phyllosilicate, based on their structures [42].

2.2. Experiment Apparatus and Procedure

This research mainly involves two experimental apparatuses: (a) Sc-CO2 soaking system and (b) permeability measurement apparatus. The Sc-CO2 soaking system is shown in Figure 1(b), including a high-pressure vessel, constant temperature water bath, injection pump, and CO2 cylinders. The high-pressure vessel has a capacity of 50.0 MPa. The water provides a constant temperature environment with an accuracy of ±0.05°C. The injection pump is an ISCO 260D syringe pump with a rate of 0.001 to 107 mL/min and the maximum fluid pressure at 51.7 MPa. Our experiment set the water bath temperature at 50°C and fluid pressure at 10.0 MPa, enabling the supercritical state of carbon dioxide. The soaking time was set to 1, 3, 5, 7, and 14 days.

After the Sc-CO2 soaking of Longmaxi shale samples, we use the permeability measurement apparatus to measure the fracture permeability under various effective stress states, ranging from 1.0 to 20.0 MPa. The permeability measurement apparatus is shown in Figure 1(c). Pump A controls the confining stress of the shale fractures, and pump B controls the axial stress. Pump C controls a constant fluid pressure (200 kPa) in the upstream reservoir while the downstream reservoir is connected with the atmosphere. For our experiments, the Reynolds number could be estimated through the following equation:where ρ and μ are fluid density and dynamic viscosity, respectively. u is the flow speed and L is the characteristic linear dimension. Based on the experimental setup and experimental data, the fluid flow in the fractures is less than 1.0, and cubic law could be used to describe the linear Darcy flow [43]. Thus, the cubic law is used to calculate the fracture permeability and hydraulic aperture [44]:where ef is the fracture hydraulic aperture; k is the fracture permeability; μf is the dynamic viscosity of water; L is the contact length of the fracture; W is the width of the fracture; Q is the measured flow rate; ΔPf is the fluid pressure difference between upstream and downstream reservoirs.

We used the powder of whole-rock fractions (<74.0 μm) for the XRD analysis. The Rigaku D/Max-2500 X-ray diffractometer was used to determine the mineralogical composition alternation due to the Sc-CO2 soaking. The shale fracture samples were also characterised by the NMR analysis system, the MacroMR12-150H-I model. The NMR measured the pore size distribution of shale samples by detecting transverse (or spin-spin) relaxation time T2. The detailed mechanism of pore size characterisation could be found in [45, 46]. Moreover, the SEM images provided a direct visualisation of pores, and the apparatus we used in this research was FEI Quanta 600. After the Sc-CO2 soaking for various times, the fracture surface roughness was also characterised by a ZygoTM NewView optical profilometer [47]. The parameter, root mean square roughness, is used to represent the fracture roughness, which describes the profile height deviations from the mean line.

3. Experimental Results and Discussions

In this part, we present the permeability measurement results of shale fractures after soaking with Sc-CO2 for 1, 3, 5, 7, and 14 days. Then, the XRD results are shown to indicate the mineralogical compositions evolution in shale fractures. After that, the sample porosity and pore volume alternation due to Sc-CO2 soaking are shown. Finally, SEM images and fracture surface roughness are used to indicate how Sc-CO2 soaking changes the fracture surface structure and topography characteristics.

3.1. Fracture Permeability Evolution due to Sc-CO2 Soaking

The fracture permeability evolution results are shown in Figure 2(a). Since the fracture permeability is a stress-dependent parameter and the fracture permeability is measured under the effective stress of 1.0, 5.0, 10.0, 15.0, and 20.0 MPa. The fracture permeability decreases with the increase of the effective normal stress, which is the result of fracture closure. Under the effective normal stress of 1.0 MPa, the fracture permeability is 5.96 × 10−12 m2 for fractures not treated with Sc-CO2. With the soaking time ranges from 1, 3, 5, 7, and 14 days, the fracture permeability decreases to 1.07 × 10−11, 1.64 × 10−11, 2.47 × 10−11, 3.84 × 10−11, and 4.35 × 10−11 m2. Thus, a 7.3 times increase of fracture permeability is observed after 14 days of Sc-CO2 under the effective normal stress of 1.0 MPa. Similarly, under the effective normal stress of 20.0 MPa, the fracture permeability is 1.30 × 10−12 m2 for untreated fractures. While with the soaking with Sc-CO2, the fracture permeability increases to 3.54 × 10−12, 5.95 × 10−12, 8.67 × 10−12, 1.38 × 10−11, and 1.55 × 10−11 m2 after 1, 3, 5, 7, and 14 days. Moreover, we use the cubic law to calculate the fracture aperture from the fracture permeability data and plot the results in Figure 2(b). Similar trends are observed since the fracture permeability and fracture aperture has the same physical meaning in this research. Under the effective normal stress of 1.0 MPa, the fracture aperture increases from 8.46 μm to 11.35, 14.05, 17.21, 21.45, and 22.85 μm after soaking with Sc-CO2 for 1, 3, 5, 7, and 14 days. Under the effective normal stress of 20.0 MPa, fracture aperture increases from 3.95 μm to 6.52, 6.52, 8.45, 10.20, 12.85, and 13.65 μm after soaking with Sc-CO2 for 1, 3, 5, 7, and 14 days. Thus, our experimental results indicate that the soaking with Sc-CO2 will largely increase the shale fracture permeability and effective hydraulic aperture.

During the fracture permeability measurement, the normal stress applied on the fracture increases from 1.0 to 5.0, 10.0, and 15.0 and finally reaches 20.0 MPa. The permeability and effective hydraulic aperture decrease are the results of fracture closure. The parameter fracture normal stiffness is commonly used to characterise the fractures’ ability to resist the normal closure, and the definition is the rate of change in normal stress with respect to fracture closure [48]:where un is the normal displacement (positive for closure), ef is the fracture aperture, and σn is the effective normal stress applied on the fracture.

Thus, we plot the relationship between fracture normal closure and effective normal stress in Figure 3(a), and the results show a highly nonlinear normal closure behaviour of fractures due to the effective normal stress increase. In a recent model developed by Zangerl et al. [49], a linear relationship was proposed to constrain the relationship between the logarithm of effective normal stress and fracture normal closure:where A is a stiffness characteristic and B is the logarithm of the reference normal stress. Thus, we further plot the relationship between the logarithm of effective normal stress and fracture normal closure in Figure 3(b), where a linear relationship is presented.

Additionally, it could be found that fracture aperture is a stress-dependent parameter and the fracture stiffness is also largely affected by the effective normal stress. Thus, the relationship between normal stiffness and effective normal stress could be expressed as follows [50]:where dkn/dσn is a constant that is referred to “stiffness characteristic” [49, 50]. Thus, we further plot the relationship between fracture normal stiffness and effective normal stress shown in Figure 3(c). A linear relationship is observed between fracture normal stiffness and effective normal stress. This observation is as same as laboratory-scale and in situ description of granite fractures.

The parameter-stiffness characteristic, dkn/dσn, should be constant and independent with normal stress and could be used to describe the fracture’s normal stiffness. Furthermore, we calculate the dkn/dσn evolution with soaking times for our fractures and plot this in Figure 3(d). The results show that the stiffness characteristics value decreases from 122.91 mm−1 to 73.57, 67.93, 69.17, 63.93, and 64.05 mm−1 after soaking with Sc-CO2 for 1, 3, 5, 7, and 14 days. Thus, the fracture normal stiffness decreases with the increasing soaking times with Sc-CO2, which indicates that the soaking with Sc-CO2 will decrease normal stiffness. This observation is in accordance with the previous research that the exposure to the Sc-CO2 will shale competencies and deteriorate its mechanical properties [31, 34]. Thus, the fractures will be more easily compressed and induce fracture aperture closure after soaking with Sc-CO2. It is worth mentioning that the stiffness characteristics are 63.93 mm−1 and 64.05 mm−1 after soaking with Sc-CO2 for seven days, separately. The similar values may indicate there may be a threshold for the fracture normal stiffness degradation: after seven days with Sc-CO2 soaking, the fracture normal stiffness will reach a threshold value and will not decrease much for further soaking with Sc-CO2.

3.2. Fracture Mineralogy Evolution due to Sc-CO2 Soaking

To identify the possible chemical reactions that occur in the fracture surface due to Sc-CO2 soaking and explore the mechanisms for fracture permeability evolution, we also performed the XRD analysis to quantify the mineralogical composition evolution [51]. As mentioned before, all minerals are grouped into three categories: tectosilicate, carbonate, and phyllosilicate, and we show three groups of mineralogy evolving with soaking times in Figure 4(a). The results show that the tectosilicate and phyllosilicate content increases slightly, while carbonate minerals content decreases. Since the main carbonate minerals in Longmaxi shale are calcite and dolomite, we further plot the calcite and dolomite mineral evolution with soaking times in Figure 4(b). The results also indicate that both calcite and dolomite minerals contents decrease with soaking times. The alterations in mineralogical compositions should be related to the complicated chemical reaction between Sc-CO2 and shale minerals. Previous researches have summarised some potential chemical reactions [26]:

During the Sc-CO2 soaking, H+ may exist when CO2 meets the original water in the shale samples, forming the carbonic acid (H2CO3). At the same time, calcite is a kind of stable polymorph of calcium carbonate (CaCO3). Thus, the calcite may react with H+ and result in the Ca2+, and through this process, the calcite mineral dissolves. Similarly, dolomite is composed of calcium magnesium carbonate, ideally, CaMg(CO3)2, and it may react with H+ and result in Ca2+ and Mg2+. Thus, the dissolution of calcite and dolomite will decrease the relative content with Sc-CO2 soaking and induce the relative increase of the content of tectosilicate and phyllosilicate. It is also worth mentioning that after seven days of soaking, the mineral content does not change dramatically, which is in accordance with permeability evolution. Thus, we may believe seven days may be a threshold that the chemical reactions terminate, and the shale fractures become stable after seven days of soaking with Sc-CO2.

3.3. NMR Characterisation of Pore Volume Alternation

The NMR methods provide information on pore volume distribution of shale before and after Sc-CO2 soaking. As shown in Figure 5, the pores could be divided into three categories: micropores with pore width less than 2 nm, mesopores with pore width between 2 and 50 nm, and macropores with a width larger than 50 nm. It could be easily observed that with the increase of soaking times, more pores with larger widths are observed. Additionally, we plot the pore width distribution under various soaking times in Figure 6(a). The mesopores are the dominant pore size for Longmaxi shale, with a content higher than 60%. With the increase of soaking times, the percentage of macropore increases from 26.89% for untreated samples to 27.11%, 29.05%, 30.21%, 32.15%, and 32.42% after soaking with Sc-CO2 for 1, 3, 5, 7, and 14 days. Simultaneously, the percentage of mesopores and micropores has slightly decreased due to the increase of pore width, which means that the pore width distribution curves move rightwards. This observation is also in accordance with the results of average pore width, as shown in Figure 6(b). With the increase of soaking times, the average pore width increases from 11.05 nm for untreated samples to 12.35, 14.09, 15.88, 16.44, and 16.69 nm after soaking with Sc-CO2 for 1, 3, 5, 7, and 14 days. The average pore width results also validate our previous observations that after seven days of soaking with Sc-CO2, the chemical reactions terminate since the pore width after seven days of soaking has almost the same pore width as samples after 14 days of soaking.

3.4. SEM Analysis of Fracture Surfaces Evolution

We also present SEM images of fracture surfaces after soaking with Sc-CO2 for various days. It should be mentioned that the fracture surfaces were scanned after soaking with Sc-CO2 but before the fracture permeability tests. The SEM images are summarised in Figure 7. Those images were captured with the high voltage at 20 kV, and magnification was 1500 times. For untreated shale samples, we cannot see any large pores within the scope. After one day of soaking with Sc-CO2, some large pores could be observed in the scope (marked with green boundary). Those pores may be the results of the dissolution of calcite and dolomite minerals. Additionally, with increasing soaking times, it is obvious that larger pores are shown in the scanning scopes. For the cases of soaking times at three and five days, it is interesting to see some undissolved minerals within the pores, which we mark with the red boundaries. Those minerals may need more time to be dissolved, and we cannot see those inner-pores minerals after soaking times more than seven days.

3.5. Fracture Surface Roughness Evolution

The optical profilometry method is used to quantify the shale fracture roughness evolution due to the soaking with Sc-CO2 and compression effect during the permeability tests, as shown in Figure 8. The black squares and red circles in Figure 8 represent the root mean square roughness after the soaking and before the permeability tests. The results show that the root mean square roughness increases from 26.19 μm to 29.33, 33.14, 35.12, 39.14, and 40.12 μm after soaking with Sc-CO2 for 1, 3, 5, 7, and 14 days. The fracture roughness should be the result of carbonate mineral dissolution, in which the calcite and dolomite minerals are dissolved and removed with water. The removed minerals leave pore spaces in the fracture surface and thus create more valleys and increase the root mean square roughness. While after the permeability measurement, the root mean square roughness decreases to 20.21, 23.22, 26.54, 28.33, 30.32, and 29.14 μm, as shown by the red circles in Figure 8. The roughness reduction is the result of mechanical reduction of fracture asperities during permeability measurement tests where the effective normal stress increases from 0 to a maximum of 20.0 MPa. The increase of effective normal stress compacts the fracture surface asperities and causes plastic deformation or damage that cannot be recovered. The reduction of root mean square roughness is also plotted in Figure 8 by the blue triangles. It is interesting to observe that a severe roughness reduction and possible fracture asperities damage are shown with the increase of soaking times. This observation is in accordance with our previous analysis of fracture stiffness characteristics. With the soaking of Sc-CO2, the shale fractures are more easily damaged, and the decrease of normal stiffness is observed (Figure 3(d)).

4. Implications for Sc-CO2 Fracturing and Potential CO2 Sequestration

Our experimental observations indicate that the soaking with Sc-CO2 increases the fracture permeability by ∼7.3 times and the corresponding fracture aperture ∼2.7 times after 14 days. The XRD and SEM results showed that shale fracture permeability increase results from calcite and dolomite mineral dissolution and more pore spaces are created in the fracture surfaces. Another critical issue is the time threshold for Sc-CO2, and shale reaction may last for seven days. The shale fracture permeability will stay stable, and fracture surface roughness does not change much. Those observations may deepen our understanding of Sc-CO2 as the fracturing fluid for shale gas hydraulic fracturing and potential CO2 sequestration in shale reservoirs.

Sc-CO2 fluid has been proposed as the fracturing fluid candidate for shale reservoir hydraulic fracturing operations due to its possibility of lowering the breakdown pressure and creating complex fracture networks [16, 19]. During the hydraulic fracturing operations, the fluid injection may last one to two weeks based on the reservoir volume. Based on the results in our research, after creating hydraulic fractures in shale reservoirs, the fracture permeability may increase several times due to the continuous Sc-CO2 injection through the carbonate mineral dissolution process. However, fracturing-induced fractures are easily compressed due to the in situ stress since the depth may be larger than 5,000 m, and the effective normal stress may be larger than 100.0 MPa. The exposure of shale fractures to Sc-CO2 will decrease the fracture stiffness, which may induce larger fracture closure under the in situ stress states. Thus, some last steps such as proppant injection should be performed to keep the fracture open and for effective shale gas production.

As for the deep geological CO2 sequestration, the low permeability shale could be the target formation since it has high ability to absorb CO2 in the shale matrix. One critical factor that determines whether CO2 sequestration is a success is the long-term sealability of the reservoir. Thus, fractures and faults should be avoided in the sealing reservoirs. As we observed in this study, the shale fracture permeability may increase several times, and those fractures may work as the CO2 leakage paths. On the one hand, those fractures and faults should be carefully understood before the large-scale injection of CO2 into the reservoir through geological investigation. On the other hand, deep CO2 sequestration is a long-timescale project, which aims to seal the CO2 underground for hundreds and thousands of years. If the chemical reaction terminates after several days of soaking with CO2 and the interactions between shale rock and CO2 are weak after certain times, which is much less than the timescale of the whole project, the effect of CO2 soaking on shale fracture permeability evolution may be neglected when considering the whole project design. Last but not least, geological CO2 sequestration is a complicated process, and the original water content in the reservoir cannot be ignored, which may accelerate the chemical reactions between shale and Sc-CO2, and further research is meaningful in this topic.

5. Concluding Remarks

We perform a series of shale fracture soaking tests with Sc-CO2 and measure the fracture permeability evolution under various stress states to investigate the effect of Sc-CO2 soaking on the shale fracture permeability evolution. Some supplementary test techniques are combined to identify the fracture mineralogical composition, pore characteristics, pore structure, and fracture roughness alternation from a microscale aspect. Our experimental observations indicate that the soaking with Sc-CO2 may increase the shale fracture permeability through the chemical dissolution of calcite and dolomite minerals, which create more macropores in the fracture surface. The fracture aperture increase is in accordance with the observation of fracture surface roughness alternation, where peaks and valleys are formed. This chemical reaction process may last for almost seven days, after which the chemical interaction between shale fractures and Sc-CO2 fluid may be neglected and the whole system becomes stable. Moreover, soaking with Sc-CO2 will decrease the stiffness of shale fractures, which makes the fractures more easily compressed (close) due to effective normal stress. Our results validate the possibility that using Sc-CO2 as the fracturing fluid may further increase the shale fracture permeability and reservoir permeability due to hydraulic fracturing. Due to its relatively short timescale, this process may not be that important in considering long-term deep CO2 sequestration.

Data Availability

The data used to support the findings of this study are plotted within the article, and the raw data files are available by contacting the corresponding author.

Conflicts of Interest

The authors declared that there are no conflicts of interest regarding this work.


Zhaohui Lu acknowledges the funding from the National Natural Science Foundation of China (No. 52074059), Chongqing Science Foundation for Distinguished Young Scholars (cstc2021jcyj-jqX0007) and Performance Incentive Guidance Special Project of Chongqing Research Institutions (cstc2020jxjl90001). Pei He acknowledges the funding from the National Natural Science Foundation of China (No. 52004047). Yunzhong Jia acknowledges the support from the Open Project of National and Local Joint Engineering Research Center of Shale Gas Exploration and Development, Chongqing Institute of Geology and Mineral Resources (Project No. YYQGDZX-202002).