Supercritical carbon dioxide fracturing in shale and the coupled effects on the permeability of fractured shale: An experimental study

Journal of Natural Gas Science and Engineering 36 (2016) 369e377

Contents lists available at ScienceDirect

Journal of Natural Gas Science and Engineering journal homepage: www.elsevier.com/locate/jngse

Supercritical carbon dioxide fracturing in shale and the coupled effects on the permeability of fractured shale: An experimental study Junping Zhou a, b, *, Guojun Liu a, b, Yongdong Jiang a, b, Xuefu Xian a, b, Qili Liu a, b, Daochuan Zhang a, b, Jingqiang Tan c a b c

State Key Laboratory of Coal Mine Disaster Dynamics and Control, Chongqing University, Chongqing, 400044, China College of Resources and Environmental Science, Chongqing University, Chongqing, 400044, China Department of Earth and Atmospheric Sciences, University of Houston, TX, 77204, USA

a r t i c l e i n f o

a b s t r a c t

Article history: Received 27 July 2016 Received in revised form 29 September 2016 Accepted 5 October 2016 Available online 14 October 2016

Supercritical carbon dioxide (ScCO2)-based reservoir fracturing associated with CO2-enhanced shale gas recovery is a promising technology to reduce water utilization in shale gas production and has the potential for CO2 sequestration. In the current research, experiments were conducted to explore the effectiveness of ScCO2 fracturing and the permeability of fractured shale under in situ stress and pore pressure. Computerized tomography scanning (CT scan) was used to characterize the fracture morphology. The results indicate that ScCO2 fracturing can induce complex fractures with various branches, which benefits the reservoir stimulation. There is a negative power relationship between the effective stress and permeability. However, the permeability reduction with effective stress depends on the stress path. The permeability substantially decreases with increasing effective stress, which is caused by the increase of the confining pressure. Nevertheless, the permeability decreases slowly when the increase of effective stress results from a decrease of the pore pressure. In addition, CO2 adsorption induces shale matrix swelling, influences the mechanical properties of shale, which significantly decreases the permeability of the shale, and the effect of adsorption on shale permeability is related to the stress state. © 2016 Elsevier B.V. All rights reserved.

Keywords: Shale gas Supercritical carbon dioxide fracturing Permeability Klingkenberg effect Adsorption-induced swelling

1. Introduction Shale gas has become an increasingly important source of natural gas all over the world. The recoverable global shale gas resources are approximately 207
1012 m3, accounting for 32% of the total natural gas resources of the world (EIA, 2011). The United States is the first country that achieved large-scale commercial exploitation of shale gas. The rapid development and production of shale gas rely on the breakthrough and development of horizontal drilling and hydraulic fracturing technology (King, 2010; Nagel et al., 2013; Tan et al., 2014a,b; Rutqvist et al., 2015). Currently, slick-water is the most common fracturing fluid used for the commercial shale gas development. However, aqueous-based

* Corresponding author. State Key Laboratory of Coal Mine Disaster Dynamics and Control, Chongqing University, Chongqing, 400044, China. E-mail address: [email protected] (J. Zhou). http://dx.doi.org/10.1016/j.jngse.2016.10.005 1875-5100/© 2016 Elsevier B.V. All rights reserved.

fracturing fluids show notable drawbacks, including but are not limited to: 1) the potential to block gas flow channels, which substantially weakens shale gas production because water causes clay minerals to swell (Dehghanpour et al., 2012; Richard et al., 2015); 2) limited water availability may restrict shale gas production in water-scarce regions. The fracturing of a typical shale gas well requires 14,000e24,000 m3 of water depending on the drilling depth of the well, number of fracturing stages, and length of laterals (Nicot and Bridget, 2012; Scanlon et al., 2014; EPA, 2010). A significant amount of water can be lost in the fracturing process. The recovery ratio of the flow back water can be as high as 80% and as low as 15% depending on the geological conditions of the reservoir (GWPC, 2009); and 3) in addition to water, the fracturing fluids contain chemical additives (e.g., friction reducers, thickening agents, gelling agents, crosslinkers, swelling inhibitors, corrosion inhibitors, breakers, biocides, and stabilizers) and proppants, which may affect groundwater and surface water (Estrada and Bhamidimarri, 2016; Song et al., 2015; Orem et al., 2014; Aminto

370

J. Zhou et al. / Journal of Natural Gas Science and Engineering 36 (2016) 369e377

and Olson, 2012). Therefore, concerns about water usage and the environmental footprint of shale gas development are increasing (Ziemkiewicz et al., 2014). To overcome these drawbacks, an increasing number of researchers are exploring less waterintensive or waterless fracturing technologies (Richard et al., 2015). Because supercritical carbon dioxide (ScCO2) has a low viscosity and high diffusion capacity similar to gas and a high density similar to liquid, it has been considered to be an ideal non-aqueous fracturing fluid for shale gas exploitation. Compared to aqueous fluids, ScCO2 is able to induce more complicated fractures due to its low viscosity, enhance shale gas recovery by displacing adsorbed methane in shale, reduce the water footprint, and minimize environmental impacts (Peng et al., 2015; Xian et al., 2015). Moreover, ScCO2-based fracturing technology offers the opportunity for CO2 sequestration in shale gas reservoirs (Stauffer et al., 2011; Middleton et al., 2012). Inspired by the shale gas revolution in the US, China is trying to replicate successful shale gas exploitation (Tan et al., 2013, 2014a, b; Hu et al., 2016; Zhang et al., 2015; Tian et al., 2013; Wu et al., 2014). China has the largest estimated reserves of recoverable shale gas in the world, estimated to be 25
1012 m3 (Jia et al., 2012). Shale gas reservoirs are widely distributed in marine and continental deposits in China. Marine shale is mainly found in South and North China, such as in the Sichuan and Tarim basins. Continental shale is primarily located in North China, such as in the Turpan-Hami, Junggar, Ordos, Songliao, and Bohaiwan basins (Tan et al., 2013). However, many of these regions are water-scarce areas. The development of waterless technologies to reduce the reliance on water in fracturing shale reservoirs is therefore necessary. Supercritical CO2 fracturing is undoubtedly one of the most promising technologies for shale gas production in China. Research on the effectiveness of ScCO2 fracturing and the permeability of fractured shale under in situ stress and pore pressure is very important to understanding long-term shale gas production (Gao and Hu, 2016; Cao et al., 2016; Ma et al., 2016; Cai et al., 2012). To the best of our knowledge, there are few experimental studies in these areas and some fundamental issues still need to be clarified. In this work, a ScCO2 fracturing experiment was conducted on shale samples, the acoustic emissions (AEs) were monitored over the experimental process, and the fracture morphology before and after fracturing was determined using computer tomography (CT) to examine the fracture mode and features of the induced fractures. In addition, the effects of stress, pore pressure, and gas adsorption on the permeability of the fractured shale samples were illustrated. The results of this study could benefit shale gas extraction and carbon dioxide sequestration in China. 2. Materials and experiments 2.1. Sample preparation The analyzed shale samples used in this work were collected from an outcrop of the lower Silurian Longmaxi formation located in the Changning (CN) region of the Sichuan Basin. This area is currently the most promising location of marine shale gas exploration and development in China (Tan et al., 2013). The shale interval of the Longmaxi formation is primarily composed of dark

gray and black silty shale, siliceous shale, and organic-rich carbonaceous shale. The total organic carbon (TOC) content is 4.18% and the vitrinite reflectance (R0) is 2.36%. These values are optimal for the occurrence of shale gas (TOC  2%, 3%  R0  1%; Zhang et al., 2011). Table 1 summarizes the mineralogical composition of the shale samples according to X-ray diffraction (XRD). The XRD measurements were performed using a Rigaku D/Max-2500/PC type X-ray diffractometer with Cu Ka radiation. The diffraction data were collected over a 2q range from 5 to 80 at a rate of 2q ¼ 1 min1. The generator settings were 40 kV and 30 Ma, and the sample particle size was 125e150 mm. Subsequent to the organic geochemical and XRD mineralogical characterizations, the sample was drilled in the vertical direction to the bedding plane to obtain cylinder samples for the ScCO2 fracturing experiments. The cylinder samples are 100 mm in diameter and 200 mm in length. 2.2. Apparatus This study includes two types of experiments: hydraulic fracturing of the shale samples by ScCO2 and permeability tests of the fractured shale samples under different effective stresses using different types of gas. All experiments were conducted using an advanced hydraulic fracturing test apparatus (Fig. 1). The apparatus was specifically designed for ScCO2 fracturing and was composed of five subsystems: a CO2 injection system, triaxial loading and control system, temperature control system (oil bath), acoustic emission monitoring system, and real-time data acquisition system. CO2 injection was conducted using an ISCO (260D) syringe pump (Teledyne ISCO, USA). The temperature was controlled using a temperature-controlled thermostatic oil bath, which maintains the temperature within a 0.1  C fluctuation range of the set point. Thus, the CO2 phase can be precisely controlled. The triaxial loading and control system allows the triaxial cell to accommodate the cylindrical sample and applies an independent load on the sample in the radial and axial directions via electro-hydraulic servo pumps with confining pressures ranging from 0 to 25 MPa and axial stresses ranging from 0 to 35 MPa (s1 > s 2 ¼ s 3). The control accuracy is ±1% of the set value. The new setup is able to provide a high fluid injection pressure (up to 50 MPa, with the controlling accuracy of 0.01 MPa) and a temperature (20e100  C) similar to the reservoir conditions. Therefore, the system is capable of simulating the ScCO2 fracturing process of a shale reservoir under in situ stress, pressure, and temperature conditions and can be used to conduct permeability testing on reconstituted rock samples or fractured rock samples using fluid with different phases (gas, liquid, and/or supercritical). During the experiment processes, the data for axial stress, confining pressure, fluid pressure, temperature, acoustic emission, and strain were monitored and recorded by a real-time data acquisition system. 2.3. Sample design and seal method Prior to the fracturing experiment, an axial central borehole with an 8-mm diameter was drilled to a depth of 140 mm (Fig. 2). An injection pipe was inserted into the borehole to ensure the tightness of the system during the experiment process. Epoxy was

Table 1 Mineralogical composition (wt%). Name

Quartz

Calcite

Dolomite

Plagioclase

K-feldspar

Iron pyrites

Barite

Karstenite

Clay

Data

40.2

11.7

19.3

3.8

0.8

2.7

1.0

0.4

20.1

Note: Clay minerals represent the total amount of kaolinite, montmorillonite, illite, and chlorite.

J. Zhou et al. / Journal of Natural Gas Science and Engineering 36 (2016) 369e377

371

Fig. 1. Schematic of the ScCO2 fracturing and fluid flow system (Xian et al., 2015).

filled into the interface between the injection pipe and wall of the borehole. A platen with an internally thread bore was connected to the injection port. An O-ring encircling the center of the injection port was used to seal the joint interface. The sample was sealed with a heat shrinkable sleeve and silicon in the triaxial load cell and a porous disk was used to inject fluid into the sample. The sample sealing method and installation procedure are shown in Fig. 3. Validation experiments were conducted to verify the effectiveness of the sealing method. 2.4. Experiment procedure

Fig. 2. Sample design.

The ScCO2 fracturing experiments were conducted at the temperature of 35  C, with an axial stress (s1) ¼ 20 MPa, confining stress (s2 ¼ s3) ¼ 15 MPa, and constant fluid injection rate of 30 ml/ min. The CO2 pressure and acoustic emissions (AEs) were simultaneously monitored and recorded. The fracture morphology of the shale samples was characterized before and after the fracturing experiments using surface observations and computer tomography (CT) scanning to determine the fracture mode and characterize the induced cracks. The surface fracture morphology of the shale samples was characterized with a high-definition camera. The morphology of the interior fractures was determined using a customized CT scanning machine developed at Chongqing

372

J. Zhou et al. / Journal of Natural Gas Science and Engineering 36 (2016) 369e377

Fig. 3. Sample installation procedure.

University. The resolution was 4096 pixels
4096 pixels. Permeability is one of the most fundamental properties required for modeling shale gas production. The permeability of the reservoir shale significantly depends on the in situ stress, pore pressure, temperature, gas composition, and adsorption (Cui et al., 2013). In the current research, the effects of the effective stress, pore pressure, and gas adsorption on the permeability of fractured shales were analyzed using ScCO2 fracturing experiments and different type of gases. The effective stress was controlled by changing the confining pressure or gas injection pressure. The permeability of the fractured shale was measured with the steady-state method. The Darcy flow equation, Eq. (1), was used to interpret the experimental results of the measured permeability (Jasinge et al., 2011). The permeability of the fractured shale obtained from the experiments was calculated using Eq. (1).

k¼

2QP0 mL
A p21  p22

(1)

where k ¼ permeability, 103 mm2; Q ¼ gas flow rate, cm3/s; P0 ¼ atmospheric pressure, 0.1 MPa; m ¼ dynamic viscosity, MPa.s; L ¼ sample length, mm; A ¼ specimen cross section area, cm2; P1 ¼ injection pressure, and P2 ¼ outlet pressure, MPa. 3. Results and discussion 3.1. ScCO2 fracturing experiment results 3.1.1. ScCO2 fracturing breakdown pressure and AEs The tests were conducted in triplicate to confirm the trends of the results. Table 2 summarizes the breakdown pressure and orientation of the induced fractures. Although the measurements were conducted under the same stress conditions and fluid injection rate, the breakdown pressure varied among the samples. This phenomenon was most likely caused by preexisting fractures in the cylindrical samples. A typical fluid pressure versus time curve for a tested sample (CN-3) is shown in Fig. 4. It indicates that the breakdown pressure of the CN-3 shale sample was 14 MPa. Compared to the results of the hydraulic fracturing experiments on shale samples from the CN area, the breakdown pressure of ScCO2 was lower than that of water. This is because the viscosity of ScCO2 is lower than that of

water. This observation is consistent with previous observations on granite specimens (Chen et al., 2015b). The number of AEs vs. CO2 pressureetime curve is shown in Fig. 5. The AE features can be divided into four stages. At stage A, CO2 pressure accumulated in the borehole and the speed of pressure accumulation was very fast. No notable fractures developed in the sample or a natural fracture had not opened, and the number of AEs was rare. At stage B, the CO2 injection continued and the pressure vs. time curve became smoother than in stage A. CO2 entered into some of the natural fractures; thus, some AEs were observed. However, no new fractures were generated in this stage; hence, there was only a small number of AEs. The breakdown pressure was reached at stage C. The fractures continued to initiate and propagate, and the number of AEs increased significantly. The propagation of the fractures continued until stage D, which was still characterized by a large number of AEs. As the pressure decreased, the fractures connected completely and the number of AEs decreased. 3.1.2. Fracture morphology of ScCO2-fractured shale The fracture morphology of all test shale samples shows that ScCO2 fracturing can induce complex fractures with branches, which is very beneficial for the stimulation of shale gas reservoirs. The fracture morphology observed with a high-definition camera and CT scanning before and after the fracturing experiments on the CN-3 shale sample is shown in Figs. 6 and 7. The original shale sample is very tight and has few natural fractures, but a complex fracture network was observed after ScCO2 fracturing. The results indicate that ScCO2 fracturing is potentially a very effective technology for stimulating shale gas reservoirs. The elastic theory and rock failure criteria tell us that the fractures propagate in the perpendicular direction to the minimum in situ principal stress. Fractures perpendicular to the horizontal direction penetrating the whole sample in the vertical direction were observed in this study, with s2 ¼ s3 ¼ 15 MPa as the minimum principal stress (Fig. 7). This is consistent with the elastic theory. However, there are also some fractures parallel to the horizontal direction. ScCO2-induced fractures are dominated by shear fractures, but include tensile fractures. Fracture extension with sheardominant fractures, which occurred during the CO2 injection, is likely sensitive to defects, such as bedding weak planes, in a core. The fracture extension model with ScCO2 appeared to be different from that of water. The difference in the fracturing modes of ScCO2 and water seems to be significantly affected by the viscosity. Unlike water, ScCO2 has a high diffusivity, low viscosity, and low surface tension. It thus can penetrate into micro defects and even smaller pore spaces of the shale samples. In addition to the high penetrability when the pressure of CO2 drops as the fractures extend during the fracturing process, ScCO2 could suddenly change to the gas phase. Because the compressibility of the gas state is much larger than that of the supercritical state, this phase transition could lead to the expansion of ScCO2 and induce further fracturing, which is of benefit for extending the cracks and could create more fractures in all directions. This is unique compared to conventional slick-water fracturing (Huang et al., 2015; Chen et al., 2015b). The results reveal that low viscosity fluids, such as ScCO2, widely induced extension fractures with branches. In addition, the adsorbed methane (shale

Table 2 Summary of the experimental results. Core

Injection rate (ml/min)

Breakdown pressure (MPa)

Fracture orientation

CN-1 CN-2 CN-3

30 30 30

7.6 11.9 14.0

different direction (parallel and perpendicular to bedding) different direction (parallel and perpendicular to bedding) different direction (parallel and perpendicular to bedding)

J. Zhou et al. / Journal of Natural Gas Science and Engineering 36 (2016) 369e377

373

16

CO2 pump pressure (MPa)

14 12 10 8 6 4 2 0

0

100

200

300

400

500

600

700

800

900

1000 1100 1200

time(s) Fig. 4. Typical pressure response in the hydraulic fracturing experiment (confining stress: 15 MPa; axial stress: 20 MPa; breakdown pressure: 14 MPa).

3.2. Permeability of fractured shale

Number of AEs (count/4s)

3.2.1. Effect of the effective stress and gas adsorption on fractured shale permeability The effects of the effective stress on the permeability of fractured shale depending on different types of gas are shown in Fig. 8. The experiments were performed under a constant gas injection pressure of 4 MPa. The effective stresses were controlled by changing the confining pressure at each step. The CO2 and N2 gases reached adsorption equilibrium in each permeability test. The

results indicate that the gas permeability of the fractured shale is highly stress-depended. The permeability of each gas decreases with the increase of the effective stress. The comparison of the measured permeability with He, CO2, and N2 at constant pressure and the same effective stress states shows that the sample has the highest measured permeability when He is used as the permeating fluid, while the sample has the lowest measured permeability when CO2 is used. This phenomenon can be attributed to the adsorption-induced differential swelling of different types of gas (Chen et al., 2015a; Lu et al., 2016; Yin et al., 2016). It has been recognized that CO2 has the strongest affinity to organic matter and N2 has a relatively weak affinity, whereas, in general, shale constituents cannot absorb He. Thus, CO2 induced the largest swelling in the shale among the three gases. Because the adsorptioninduced swelling narrowed the fracture in the shale sample, the measured permeability of the fractured shale was reduced and the measured permeability of the shale sample using CO2 was the lowest. The permeabilityeeffective stress relationships can be fitted satisfactorily with a negative power function for individual gases of He, CO2, and N2, which shows a higher fitting degree than the

140

14

120

12

100

10

80

8

60

6

A

C

B

D

40

4

20

2 0

0 0

200

400

600

800

tim e (s) Fig. 5. Number of AEs vs. CO2 pressureetime curve.

1000

CO2 pressure(MPa)

gas) was displaced by the injected CO2, because the adsorption affinity of CO2 in shale is approximately 4e20 times greater than that of methane (Duan et al., 2016). The possibility of using CO2 to enhance shale gas recovery and simultaneous achieve CO2 sequestration in shale gas reservoirs has thus been anticipated (Zhou et al., 2012; Jiang et al., 2016). The expansion effect of ScCO2 could improve the sweep efficiency of the displacement process because it would extend the scope of the cracks and create more exposed surface area for the adsorption of CO2 and desorption of CH4.

J. Zhou et al. / Journal of Natural Gas Science and Engineering 36 (2016) 369e377

Fig. 6. Photographs of the observed fractures on the surfaces. (a) transverse section (vertical to the borehole direction, depth ¼ 140 mm).

permeability(10-3 m2)

374

CO2 exponential function fit curve

commonly used negative exponential relationship. The fitting equations of both relationships can be given as follows.

(2.1)

k ¼ 0:1256 exp0:0226se ; R2 ¼ 0:9162

(2.2)

0:037se

k ¼ 0:1139 exp

2

; R ¼ 0:8950

4

6

effective stress(MPa)

He : k ¼ 0:1353s0:1257 ; R2 ¼ 0:9949 e

N2 : k ¼ 0:1285s0:2087 ; R2 ¼ 0:9902 e

2

Fig. 8. Permeability of fractured shale depending on the effective stress and different gases.

(3.1)

According to equations (2)e(4), the power relationships of the permeabilityeeffective stress can be fitted with the general equation:

k ¼ AsB e

(5)

(3.2)

CO2 : k ¼ 0:0652s0:4016 ; R2 ¼ 0:9830 e

(4.1)

k ¼ 0:0547 exp0:0822se ; R2 ¼ 0:9823

(4.2)

where se is the effective stress and A and B are the fitting coefficients. A depends on the initial permeability and stress states, and B represents the curvature of the fitting curve, which can be defined as the stress sensitivity coefficient. It is worth noting that He has the highest value of A and lowest value of B, whereas CO2 has the lowest value of A and highest value of B. This means that He has the highest initial permeability and lowest stress sensitivity, while CO2 has the lowest initial permeability and highest stress sensitivity. The difference in initial permeability of each gas is related to the experiment procedure because the experimental procedure uses He, N2, and CO2 successively. For the same sample, the result ofAHe > AN2 > ACO2 indicates that some irreversible deformation of the shale sample induced by the effective stress and adsorption-induced swelling occurred in the previous experimental step. This leads to a decrease of the initial permeability. The difference of the stress sensitivity coefficient of the different gases may be due to the adsorption-induced mechanical property changes. There is a decrease in both the uniaxial compressive strength and elastic modulus of the shale samples that adsorbed CO2 (Lyu et al., 2016). The adsorbed CO2 allows easy compression of the shale sample, and the stress sensitivity coefficient of CO2 is the highest. It is interesting to note that even under constant pore pressure conditions, the effect of adsorption on the permeability is not constant. Table 3 shows the coupling effects of the effective stress and adsorption-induced swelling as well as the mechanical properties changes on shale permeability. We assume that He is not

Table 3 The coupling effects of the effective stress and adsorption-induced swelling.

Fig. 7. Images of the interior fractures observed by CT scanning before and after fracturing. (b) longitudinal section (parallel to the borehole direction).

se

kHe

kCO2

Dk ¼ kHe  kCO2

3 5 7 9 11

0.1179 0.1105 0.1060 0.1027 0.1001

0.1022 0.0919 0.0856 0.0813 0.0779

0.0156509 0.0186550 0.0203 0.0214 0.0222

J. Zhou et al. / Journal of Natural Gas Science and Engineering 36 (2016) 369e377

3.2.2. Effect of the different effective stress paths on the fractured shale permeability Permeability measurements with different stress paths were performed on CN-1 and CN-3. The effective stress was changed by two different approaches: the first approach reduced the pore pressure gradually, while maintaining a constant confining pressure in the tests, and the second approach increased the confining pressure at a constant pore pressure. The first approach intended to simulate the primary production scenario of shale reservoirs, where the pore pressure decreases, while the effective stress increases during the process of shale gas production, which potentially impacts the reservoir permeability. Fig. 10 shows the variation of the measured permeability as a function of the pore pressure. The pore pressure decreased gradually from 9 MPa to 2 MPa, while the confining pressure was maintained at 10 MPa during the experiment. It can be seen that the variation of the measured permeability as a function of the pore

0.023 0.022 0.021

Δ k(10

-3

2

m)

0.020 0.019 0.018 0.017 0.016 0.015

2

4

6

8

10

effective stress (MPa) Fig. 9. Variation of Dk at different effective stresses.

12

0.08

0.06

-3

2

m)

0.07

permeability(10

adsorbed by shale. Thus, under a constant pore pressure and a different stress state, Dk ¼ kHe  kCO2 , which is the contribution of the adsorption effect on the fractured shale permeability. Fig. 9 shows the contribution of the adsorption effect on permeability (Dk) under different effective stresses. It indicates that with increasing effective stress, Dk increases. This may be related to the influence of the effective stress on the gas adsorption and adsorption-induced mechanical property change (Hol et al., 2014). The effective stress can influence Dk through two different functions. First, the increase of the effective stress possibly reduces the adsorption amount of gas (Hol et al., 2014), decreasing the adsorption-induced swelling effect on permeability. This leads to the Dk decrease with the increase of the effective stress. On the other hand, gas adsorption could weaken the mechanical properties of shale compared with the non-adsorbed gas environment. Dk thus increases with the increasing effective stress. Compared to the lower effective stress level, however, the decreased amount of adsorbed gas will strengthen the mechanical properties at a higher effective stress state, which slows the increase rate of Dk as the effective stress rises. The effects of adsorption-induced swelling and adsorption-induced mechanical properties changes on Dk are therefore opposite. The fact that Dk increases with increasing effective stress indicates that the adsorption-induced mechanical properties changes coupled with the effective stress effect play a more prominent role in the change of Dk than the adsorptioninduced swelling effect.

375

0.05

CN-3He

0.04

CN-3N2

0.03

CN-1N2

CN-1He

0.02 0.01 10

9

8

7

6

5

4

pore pressure(MPa)

3

2

1

Fig. 10. The permeability of fractured shale at different gas pressures (constant confining pressure ¼ 10 MPa).

pressure of these two samples is different. The permeability of CN-1 decreases with decreasing pore pressure when He and N2 are used as pore fluids. The decrease in permeability may be caused by (1) the increase of the effective stress close to the micro-fracture or (2) gas adsorption-induced swelling and mechanical properties changes narrowing the small fracture and nanopores. The permeability of CN-3, however, varies insignificantly with the pore pressure. This is likely because: (1) the effective stress increases as the pore pressure decreases, which reduces the sample permeability. Nevertheless, the enhanced Klinkenberg effect at lower pore pressure could compensate for part of the permeability reduction; (2) a CN-3 fracture may still occur under a small effective stress; and (3) the presence of large fractures reduces the adsorption effect. Overall, the Klinkenberg effect may play a predominant role in determining the permeability of CN-3. The permeability of CN-3 as a function of the confining pressure is illustrated in Fig. 8. The results indicate that the permeability significantly decreases with increasing confining pressure. Generally, the permeability deceases with increasing effective stress in all samples. However, the permeability reduction may behave differently under certain conditions. For example, it decreases very slowly when the increasing effective stress results from pore pressure reduction. This is likely caused by the enhanced Klinkenberg effect at low pore pressure, which partly compensates for the permeability reduction due to the increasing effective stress. In contrast, permeability reduces dramatically when the effective stress increases due to the confining pressure increase. The flow channels (fractures or interconnected nanopores) may be narrowed or even closed in such scenarios and ultimately block the flow of gas. Therefore, the stress paths could significantly influence permeability during primary shale gas production and CO2 enhanced shale gas recovery. The effective stress increases with decreasing pore pressure during primary production. Hence, the permeability is reduced. However, shale gas desorption-induced shrinkage increases the permeability. The pore pressure increases when CO2 is injected into the reservoir during CO2-enhanced shale gas recovery. The effective stress then decreases, which could open fractures and enhance the permeability. Nevertheless, CO2 adsorption-induced swelling may narrow the fractures and decrease the permeability. Thus, during primary production and CO2 injection-enhanced gas recovery, the pore pressure changing paths are different and the gas adsorptionedesorption could induce mechanical properties changes of shale. Accordingly, both

376

J. Zhou et al. / Journal of Natural Gas Science and Engineering 36 (2016) 369e377

the coupled effect and stress paths should be considered when predicting the permeability of shale in primary shale gas production and CO2-enhanced shale gas recovery. 4. Conclusions In this paper, a ScCO2 fracturing experiment was conducted on Lower Silurian shale samples, and CT scanning technology was used to characterize the fracture morphology. The effects of the effective stress, pore pressure, gas adsorption, and stress path on the permeability of the fractured shale samples were analyzed. The primary conclusions are:  ScCO2 tends to induce extensive and complex fractures with many branches, and the dominant fracture type is shear fracture.  The permeability of fractured shale is highly stress-dependent, and the effective stress and permeability are negatively correlated. However, the permeability reduction with effective stress depends on the stress path. The permeability is reduced dramatically when the effective stress increase is caused by the increase of the confining pressure, whereas it decreases slowly when the effective stress increase is caused by the decrease of the pore pressure because the Klinkenberg effect enhances upon pore pressure decrease.  At a constant pore pressure and the same effective stress state, the measured permeability of the fractured shale sample using different gases (He, N2, CO2) is characterized by kHe > kN2 > kCO2 . The discrepancy of the permeability can be attributed to the adsorption-induced swelling and mechanical properties variation of the fractured shale. The contribution of the adsorption effect to permeability is related to the stress state.  During primary production and CO2 injection-enhanced shale gas recovery, the combined influences of the effective stress, pore pressure, gas adsorption, Klinkenberg effect, and stress path on the permeability of shale should be simultaneously addressed. Acknowledgments This study was financially supported by the National Basic Research Program of China (2014CB239204), the National Natural Science Foundation of China (51204218 and 51574049), the Program for Changjiang Scholars and Innovative Research Team in University (IRT13043), the Chongqing Frontiers and Application Foundation Research Program (CSTC2015jcyjys90001, CSTC2014jcyjA90025) and the Fundamental Research Funds for the Central Universities (No. 106112016CDJZR245519). References Aminto, A., Olson, M.S., 2012. Four-compartment partition model of hazardous components in hydraulic fracturing fluids additives. J. Nat. Gas. Sci. Eng. 7, 16e21. Cai, J.C., You, L.J., Hu, X.Y., Wang, J., Peng, R.H., 2012. Prediction of effective permeability in porous media based on spontaneous imbibition effect. Int. J. Mod. Phys. C 23 (7), 1250e1254. Cao, P., Liu, J.S., Yee, K.L., 2016. Combined impact of flow regimes and effective stress on the evolution of shale apparent permeability. J. Unconv. Oil Gas. Res. 14, 32e43. Chen, T.Y., Feng, X.T., Pan, Z.J., 2015a. Experimental study of swelling of organic rich shale in methane. Int. J. Coal Geol. 150e151, 64e73. Chen, Y.Q., Yuya, N., Tsuyoshi, I., 2015b. Observations of fractures induced by hydraulic fracturing in anisotropic granite. Rock Mech. Rock Eng. 48, 1455e1461. Cui, A., Nassichuk, R.W., et al., 2013. A Nearly Complete Characterization of Permeability to Hydrocarbon Gas and Liquid for Unconventional Reservoirs: a Challenge to Conventional Thinking. Unconventional Resources Technology Conference1716e1732. Dehghanpour, H., Zubair, H.A., Chhabra, A., Ullah, A., 2012. Liquid intake of organic

shales. Energy fuels.. 26, 5750e5758. Duan, S., Gu, M., Du, X.D., Xian, X.F., 2016. Adsorption equilibrium of CO2 and CH4 and their mixture on sichuan basin shale. Energy fuels.. 30 (3), 2248e2256. EIA, 2011. World Shale Gas Resources: an Initial Assessment of 14 Regions outside the United States. U.S. Energy Information Administration, Washington. EPA., 2010. Hydraulic Fracturing Research Study. Estrada, J.M., Bhamidimarri, R., 2016. A review of the issues and treatment options for wastewater from shale gas extraction by hydraulic fracturing. Fuel 182, 292e303. Gao, Z.Y., Hu, Q.H., 2016. Initial water saturation and imbibition fluid affect spontaneous imbibition into Barnett shale samples. J. Nat. Gas Sci. Eng. 30, 268e275. GWPC., 2009. Modern Shale Gas Development in the United States: a Primer: US Department of Energy. Office of Fossil Energy. Hol, S., Gensterblum, Y., Massarotto, P., 2014. Sorption and changes in bulk modulus of coal-experimental evidence and governing mechanisms for CBM and ECBM applications. Int. J. Coal Geol. 128-129, 119e123. Hu, J.G., Tang, S.H., Zhang, S.H., 2016. Investigation of pore structure and fractal characteristics of the lower silurian Longmaxi shales in western hunan and hubei provinces in China. J. Nat. Gas. Sci. Eng. 28, 522e535. Huang, F., Lu, Y.Y., Tang, J.R., Ao, X., Li, L.W., 2015. On the erosion of shale impacted by supercritical carbon dioxide jet. Chin. J. Rock Mech. Rock Eng. 34 (4), 1e8. Jasinge, D., Ranjith, P.G., Choi, S.K., 2011. Effects of effective stress changes on permeability of latrobe valley brown coal. Fuel 90, 1292e1300. Jia, C.Z., Zheng, M., Zhang, Y.F., 2012. Unconventional hydrocarbon resources in China and the prospect of exploration and development. Petro. Explo. Develo 39 (2), 139e146. Jiang, Y.D., Luo, Y.H., Lu, Y.Y., Qin, C., Liu, H., 2016. Effects of supercritical CO2 treatment time, pressure, and temperature on microstructure of shale. Energy 97, 173e181. King, G.E., 2010. Thirty Years of Gas Shale Fracturing: What Have We Learned? [C. SPE Annual Technical Conference and Exhibition, Florence, SPE133456. Lu, Y.Y., Ao, X., Tang, J.R., Jia, Y.Z., Zhang, X.W., 2016. Swelling of shale in supercritical carbon dioxide. J. Nat. Gas. Sci. Eng. 30, 268e275. Lyu, Q., Ranjith, P.G., Long, X.P., Li, B., 2016. Experimental Investigation of Mechanical Properties of Black Shales after CO2-water-rock Interaction. Materials. 9,663. Ma, Y., Pan, Z.J., Zhong, N.N., Connell, L.D., Down, D., et al., 2016. Experimental study of anisotropic gas permeability and its relationship with fracture structure of Longmaxi Shales, Sichuan Basin, China. Fuel 180, 106e115. Middleton, R.S., Keating, G.N., Stauffer, P.H., Jordan, A.B., Viswanathan, H.S., Kang, Q.J., et al., 2012. The cross-scale science of CO2 capture and storage: from pore scale to regional scale. Energy & Environ Sci. 5, 7328e7345. Nagel, N.B., Sanchez-Nagel, M.A., Zhang, F.X., Garcia, B.L., 2013. Coupled numerical evaluations of the geomechanical interactions between a hydraulic fracture stimulation and a natural fracture system in shale formations. Rock Mech. Rock Eng. 46, 581e609. Nicot, Jean-Philippe, Bridget, R.S., 2012. Water use for shale-gas production in Texas. U.S. Environ. Sci. Technol. 46, 3580e3586. Orem, W., Tatu, C., Varonka, M., Bates, A., Engle, M., Crosby, L., Mclntosh, J., 2014. Organic substances in produced and formation water from unconventional natural gas extraction in coal and shale. Int. J. Coal Geol. 126, 20e31. Peng, P., Ling, K.G., He, J., Liu, Z.Z., 2015. Shale gas reservoir treatment by a CO2based technology. J. Nat. Gas. Sci. Eng. 26, 1595e1606. nezRichard, S.M., Carey, J.W., Robert, P.C., Jeffrey, D.H., Kang, Q.J., Joaquín-Jime Martínez, S.K., Porter, M.L., Viswanathan, H.S., 2015. Shale gas and non-aqueous fracturing fluids: opportunities and challenges for supercritical CO2. Appl. Energy.147 500e509. de ric, C., George, J.M., 2015. Modeling of fault activation Rutqvist, J., Antonio, P.R., Fre and seismicity by injection directly into a fault zone associated with hydraulic fracturing of shale-gas reservoirs. J. Pet. Sci. Eng. 127, 377e386. Scanlon, B.R., Reedy, R.C., Nicot, J.P., 2014. Comparison of water use for hydraulic fracturing for unconventional oil and gas versus conventional oil. Environ. Sci. Technol. 48, 12386e12393. Song, Z.J., Liu, L.B., Hou, J.R., Bai, B.J., Su, W., 2015. Effect of polymer on gas flow behavior in microfractures of unconventional gas reservoirs. J. Nat. Gas. Sci. Eng. 23, 26e32. Stauffer, P.H., Keating, G.N., Middleton, R.S., Viswanathan, H.S., Berchtold, K.A., Singh, R.P., et al., 2011. Greening coal: breakthroughs and challenges in carbon capture and storage. Environ. Sci. Technol. 45, 8597e8604. Tan, J., Horsfield, B., Mahlstedt, N., Zhang, J., di Primio, R., Vu, T.A.T., Boreham, C.J., van Graas, G., Tocher, B.A., 2013. Physical properties of petroleum formed during maturation of Lower Cambrian shale in the upper Yangtze Platform, South China, as inferred from PhaseKinetics modelling. Mar. Petroleum Geol. 48, 47e56. Tan, J., Weniger, P., Krooss, B., Merkel, A., Horsfield, B., Zhang, J., Boreham, C.J., van Graas, G., Tocher, B.A., 2014a. Shale gas potential of the major marine shale formations in the Upper Yangtze Platform, South China, Part II: methane sorption capacity. Fuel 129, 204e218. Tan, J., Horsfield, B., Reinhard, F., Krooss, B., 2014b. Shale gas potential of the major marine shale formations in the upper yangtze platform, South China, Part III: mineralogical, lithofacial, petrophysical, and rock mechanical properties. Energy fuels.. 28, 2322e2342. Tian, H., Pan, L., Xiao, X.M., Ronald, W.T., Wilkins, et al., 2013. A preliminary study on the pore characterization of Lower Silurian black shales in the Chuandong Thrust Fold Belt, southwestern China using low pressure N2 adsorption and FE-

J. Zhou et al. / Journal of Natural Gas Science and Engineering 36 (2016) 369e377 SEM methods. Mar. Pet. Geol. 48, 8e19. Wu, Y., Fan, T.L., Zhang, J.C., Jiang, S., Li, Y.F., 2014. Characterization of the upper ordovician and lower silurian marine shale in Northwestern Guizhou province of the upper yangtze Block,South China: implication for shale gas potential. Energy fuels.. 28, 3679e3687. Xian, X.F., Yin, H., Zhou, J.P., Jiang, Y.D., Zhang, D.C., 2015. A new experimental apparatus for fracturing shale gas reservoir to enhance Permeability with Supercritical Carbon Dioxide. J. Southwest Pet. Univ. 37 (3), 1e8. Yin, H., Zhou, J.P., Jiang, Y.D., Xian, X.F., Liu, Q.L., 2016. Physical and structural changes in shale associated with supercritical CO2 exposure. Fuel 184, 289e303. Zhang, W., Guo, M., Jiang, Z., 2011. Parameters and method for shale gas reservoir

377

evaluation. Nat. Gas. Geosci. 22 (6), 1093e1099. Zhang, J.P., Fan, T.L., Li, J.g, Zhang, J.C., et al., 2015. Characterization of the lower cambrian shale in the Northwestern Guizhou province, South China: implications for shale-gas potential. Energy fuels.. 29, 6383e6393. Zhou, J.P., Xian, X.F., Lu, Y.Y., Jiang, Y.D., Liu, Z.F., 2012. Prediction of carbon dioxide storage capacity in gas shale reservoirs. Symposium Undergr. Dispos. waste, Nanchang 20e26. Ziemkiewicz, P.F., Quaranta, J.D., Darnell, A., Wise, R., 2014. Exposure pathways related to shale gas development and procedures for reducing environmental and public risk. J. Nat. Gas. Sci. Eng. 16, 77e84.