Imbibition of Oxidative Fluid into Organic-Rich Shale: Implication for

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Cite This: Energy Fuels XXXX, XXX, XXX−XXX

Imbibition of Oxidative Fluid into Organic-Rich Shale: Implication for Oxidizing Stimulation Lijun You, Qiuyang Cheng,* Yili Kang, Qiang Chen, Liandong Dou, and Yang Zhou

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State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University, Chengdu 610500, China ABSTRACT: A large amount of fracturing fluid enters a well of a shale gas reservoir to create a fracture network, but the recovery of fracturing fluid is generally less than 30%. Fracturing fluid from the hydraulic fractures usually invades the microfractures and matrix by spontaneous imbibition during the shut-in. Recent studies show that the water−rock interaction may induce shale structure failures, which can significantly affect imbibition rate. Due to the presence of oxidizable compositions (e.g., pyrite and organic matter (OM)), oxidation easily induced the structure failures and dissolution pores. However, its effects on imbibition of water into the shale is poorly understood. In this study, imbibition experiments of deionized water (DI water) and oxidative fluid under no confining pressure conditions were conducted to determine the imbibition characteristics; shale cubes (1 cm × 1 cm × 1 cm) and crushed samples (380−830 μm) were treated by DI water and oxidative fluid for revelation of the change in the composition and the associated dissolution structures and explanation of the imbibition characteristics of oxidative fluid in shale. The results show that the final amount of oxidative fluid imbibed is higher than that of DI water; oxidation-induced microfractures during the imbibition lead to a “phase step” of the normalized imbibed volume vs time curve and “S” characteristic of the normalized imbibed volume vs square root of time (sqrt time) curve. These differences are mainly caused by the improvement of the imbibition pathway and the increase of water retention space by oxidation. After the oxidation treatment of crushed shale samples for 48 h, lots of oxidation-induced microfractures and dissolution pores were observed by field-emission scanning electron microscopy. Combining the analysis of X-ray diffraction (XRD) and atomic absorption spectroscopy (AAS) found that the dissolution pores seemed to strongly contribute to the loss of calcite, dolomite, and pyrite. Results from mercury injection capillary pressure analysis showed that the oxidative dissolution could lead to a high porosity and good connectivity of nanoscale pores networks in shale cubes. Moreover, oxidative dissolution decreased the barriers of microfracture propagation according to the decrease of zeta potential in the shale−water system and, meanwhile, accelerated the release of clay hydration forces to induce microfractures. The results indicate that the coordinative effect between spontaneous imbibition and oxidative dissolution may play a significant role in increasing the gas supply ability of nanoscale pores and microfractures, thus achieving oxidizing stimulation of shale formation to enhance shale gas recovery. inorganic pore size is ∼3 and ∼10 nm in downhole gas shale samples from three different formations in the Horn River Basin.15 Amazingly, small-angle and ultra-small-angle neutron scattering (SANS and USANS) indicated that water can penetrate the vast majority of the shale matrix pores ranging from 10 nm to 10 μm in diameter.16,17 Moreover, some experiments reported that the porosity of saturated water is very close to that of saturated helium for the shale samples i.e., water can virtually enter the very small fine pores in the matrix; and the observations also suggested that the mass of water immersion increases with the rise of organic matter content in shale samples.18 Spontaneous imbibition is regarded as a primary mechanism that the operation fluid invades the shale matrix.19,20 Capillary pressure dominates the spontaneous imbibition in conventional formations.21 This usually refers to the displacement of the nonwetting phase by the wetting phase in a porous medium by capillary.22 However, the imbibition dynamics is much more complex in unconventional formations. For example, in shale formations, the electrochemical forces

1. INTRODUCTION Multistage hydraulic fracturing for horizontal wells has been successfully applied in shale gas development. Water-based hydraulic fracturing fluids are the most effective operation fluids at present.1 Tens of thousands of cubic meters of fracturing fluid is usually pumped into a well for creating a fracture network.2,3 Further, the fracturing fluid invades the microfractures and matrix by spontaneous imbibition during the shut-in, due to capillary forces and electrochemical forces, such as water adsorption by clay minerals and the osmosis effect.4−6 Since a micro- and nanoscale pore surface in shale rock exerts a strong effect on fluid retention and fracture volume closure with early flowback depletion,7 it is difficult to achieve effective flowback and the recovery of fracturing fluid is generally less than 30%.8−10 The most widely developed pore types in a shale matrix are intergranular pores and organic matter (OM) nanoscale pores, and the intergranular pore diameter is in the range 10−20 μm.11,12 Adesida et al. reported that the average organic pore sizes of Barnett shale samples are less than 10 nm.13 Zolfaghari et al. found that most of the pores sizes in shale samples, which are collected from three wells completed in the Otter-Park, Evie, and Lower-Keg-River members of the Horn River Basin, are smaller than 10 nm according to the results of both BET and the proposed model.14 Similarly, the average organic and © XXXX American Chemical Society

Received: June 22, 2018 Revised: September 21, 2018 Published: September 26, 2018 A

DOI: 10.1021/acs.energyfuels.8b02161 Energy Fuels XXXX, XXX, XXX−XXX

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Figure 1. BSE images of organic matter (OM) and pyrite in untreated shale samples. Note that the SEM imaging was performed on a gold-coated surface. a: Distribution characteristics of OM and pyrite. The dark regions of the image mainly represent OM, which behaved as a heterogeneous distribution. The white spots in the image mainly represent pyrite, which is commonly abundant in a large field of view. b: Intergranular pores in pyrite. c: Nanoscale organic pores in OM.

organic-rich shale first. Then, the role of oxidation in spontaneous imbibition for shale samples is clarified. Finally, the implication of oxidizing stimulation to enhance shale gas recovery is discussed.

owing to clay adsorption and the osmosis effect have an important influence on the imbibition.21,23 In addition to capillary forces, clay adsorption forces significantly contribute to water imbibition;24,25 chemical osmosis not only intensifies water leakoff but also hinders water flowback, which is a significant factor leading to extra-low load recovery.26 Besides, Binazadeh et al. found that the magnitude of capillary force can be altered by electrostatic interactions and that may affect the liquid uptake.27 Particularly, some imbibition experiments showed that the development of lamination and natural fracture contribute to a high imbibition volume in shale formation.28 Water rapidly imbibes along the lamination and generates cracks by shale−water interaction,4,24,28,29 and the new microfractures are regarded as a high permeability zone to increase the imbibition rate.24 In previous studies, shale−water interactions mainly focused on the effect of stress on the generation of microfractures, which was caused by physical and electrochemical reactions, have been investigated extensively.29−34 On the other hand, several past studies focused on chemical reaction between shale and water based on the chemical analysis of flowback fluid.35−37 Despite these studies indicating that the interaction between shale and water contains chemical reactions, its effects on water imbibition is seldom reported, such as oxidative dissolution. Organic-rich shale is rich in OM, pyrite, and other products deposited from the reduction environment; they are easily oxidizable under an oxygen-rich environment.38,39 The OM in clay rocks is sensitive to oxidation reactions and can be effectively removed using an oxidative fluid such as hypochlorite and bromine.40,41 Some researchers observed that the presence of pyrite can accelerate the weathering or oxidation of rocks.42 Xu et al. indicated that oxidation and dissolution of pyrite may be caused by dissolved oxygen in fracturing fluid in the reservoir. They insisted that, although pyrite constitutes only a small percentage of shale components, the oxidation reactions between pyrite and dissolved oxygen may be important to interpret the chemistry of flowback water.43 Chen et al. reported that oxidative dissolution can alter the composition and associated pore structure of Longmaxi (LMX) black shale.44 Subsequently, a new prospect that oxidation-induced rock burst enhances shale gas recovery was proposed by You et al.45 Considering that imbibitioninduced microfractures owing to water−rock interactions do improve the imbibition volume and rate,24,28 the dynamic changes in composition and structure due to the oxidation may have significant influence on the imbibition in shale. This study aims to determine the imbibition behavior of oxidative fluid in

2. SAMPLES AND EXPERIMENTAL PROCEDURES 2.1. Fluids. H2O2 has been used as an oxidant for the removal of OM in shale.46 Chen et al. reported the oxidative dissolution behavior of organic-rich shale using 15 wt % H2O2.44 Thus, H2O2 (30 and 15 wt %) was used as the oxidative fluid in this study, and it was used at densities of 1.047 and 1.111 g/cm3, respectively. Deionized water (DI water) was used to act as a contrast liquid, and its density was 0.997 g/cm3. It is not hard to find that the density of 15 wt % H2O2 is very close to that of DI water. 2.2. Shale Samples. In this study, shale samples were obtained from the lower Silurian LMX marine shale formation in Southeast Chongqing, China, where the formation occurs in a 15 000 km2 area with a thickness of 20−200 m.47 Due to the sufficiently buried depth of the LMX shale to reach gas window thermal maturity, there are such abundant gas resources that the Fuling and Pengshui counties in this district have become the hottest target zones for shale gas production.48,49 The lithofacies of this formation are generally carbonaceous black shale and siliceous black shale owing to the depositional environments of bathyal−abyssal−sea and anoxic.50 The mineralogical composition of the sample was determined by X-ray diffraction (XRD) analysis: quartz 46.3%, feldspar 8.0%, pyrite 2.6%, and carbonate minerals 10.7%. Jarvie et al. reported that a high content of brittle minerals is conducive to the generation of fracture networks.51 The total clay proportion was 32.4%; it was mainly composed of illite and mixed layers of illite/montmorillonite. The illite content was 46.0%, and the mixed-layer clay content was 42.7%. However, the chlorite content was only 11.3%. Zhang et al. showed that illite and mixed-layer clay adsorbed more water molecules than kaolinite; therefore, more clay hydration is expected.52,53 Total organic content (TOC) was 4.0%, a LECO CS230 carbon/sulfur analyzer was used to measure the TOC of the shale sample, which has removed the carbonate minerals by sufficient hydrochloric acid prior to the measurement. OM and pyrite are the main oxidizable composition in shale. Figure 1 shows the backscattered electron (BSE) images of untreated shale samples by field-emission scanning electron microscopy (FESEM), exhibiting intergranular pores in pyrite, well-developed pores in OM, and their favorable connections. Moreover, considering that shale oxidation releases H +, the dissolution of carbonate minerals would be taken into account.44,45 2.3. Experimental Procedure. Core holes were drilled parallel to the bedding structure of the shale strata (Figure 2). Four shale plugs with a core size of 2.5 cm diameter and 6.0 cm length were obtained. Meanwhile, we also further prepared eight shale cubes with a side of 1.0 cm length. Besides, over 40 g of core fragments collected in the boreholes were crushed and sieved to provide the ground samples (380−830 μm). All the experiments in this study were conducted following the procedures shown in Figure 3. B


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Table 1. Physical Property Parameters of Shale Plugs

Figure 2. Selection and preparation of shale samples.

plugs

length (mm)

diameter (mm)

porosity (%)

permeability (10−3 μm2)

LY-1

61.6

25.0

5.87

0.00824

LY-2

61.6

25.0

5.72

0.00619

LY-3

60.7

25.0

5.93

0.00541

LY-4

59.6

25.0

5.70

0.00115

experimental fluids DI water, 15 wt oxidative fluid DI water, 15 wt oxidative fluid DI water, 15 wt oxidative fluid DI water, 30 wt oxidative fluid

% % % %

II model 685 cross-section polisher (2.5 h, 5 × 10−5 Torr, 7 kV, 40− 60 mA), prior to the imaging by field-emission scanning electron microscopy (SEM, Quanta 250 FEG). To delineate the compositional and pore structure variation, a backscattered electron (BSE) image was acquired.54 Considering that the representative elementary area (REA) of the sample is between 100 μm × 100 μm and 200 μm × 200 μm,55 the polished cross-section in this investigation is over 1000 μm × 1000 μm, covering a sufficiently large field of view to observe the dissolution structure.56 2.3.3. Characterization of Mineralogy and Solution Chemistry. The crushed shale samples were divided into three groups, and the weight of samples in each group was 20.0 g. The first group was defined as the untreated sample, and the others were considered as the treated samples, which were exposed to DI water and 15 wt % oxidative fluid for 48 h, respectively. This experiments (solid-to-fluid ratio 1:20 g/mL) were conducted at room temperature in an open system. As shown in Figure 3c, the mineral composition of untreated and treated shale samples was determined using an X’Pert PRO MPD Xray diffractometer (XRD). Prior to XRD analysis, all the ground samples were further crushed, passed through a 200 mesh (>75 μm) sieve, and then dried at 60 °C for 48 h. On the other hand, the cation composition of the aqueous solution was determined using AA-7020 atomic absorption spectroscopy (AAS) to further confirm the XRD results. Karfakis et al. reported that the zeta potential of the chemical solution−rock system also plays a significant role in reflecting the rate of subcritical fracture propagation.57 In order to determine the zeta potential of the shale−water system and its change with oxidation time, another two groups of the same experiments were performed, in which the crushed shale samples were respectively exposed to 15 wt % oxidative fluid for 5 and 24 h. Drying them in an oven at 60 °C for 48 h, the treated samples (treatment for 0, 5, 24, and 48 h, respectively) were first sonicated for ∼10 min in the background solution, and then, samples of the supernatant were taken for electrophoretic mobility measurements with microelectrophoresis (Zeta-PALS, Brookhaven). Measurements were repeated five times at 25 °C, and electrophoretic

2.3.1. Spontaneous Imbibition Experiments. The effect of oxidation on the imbibition of fluids into organic-rich shale was evaluated (Figure 3a). First, spontaneous imbibition of DI water was conducted on the shale plugs; the imbibition apparatus in this study is similar to that reported by Sun et al. and Ghanbari et al.4,28 Second, after drying these samples in an oven at 60 °C for 48 h, imbibition experiments of oxidative fluid (30 and 15 wt %) were performed. In order to simulate that the fracturing fluid transports from the fracture face into the matrix in the shale gas reservoir, the shale plugs had only one side immersed 1 mm into the liquid with the other sides facing air. The accurate measurement of mass change at the selected time intervals was carried out using an analytical balance with a readability of 0.0001 g. The initial weight was measured prior to the experiment. Changes in the plugs surface were observed during the imbibition. Table 1 provides some information about the materials of this experiment. The porosity and permeability were measured by a helium porosimeter and pulse decay permeameter, respectively. 2.3.2. Observation and Characterization of Dissolution Structure. The shale cubes were divided into four groups, and the amount of samples in each group was two. The first group defined as the untreated sample, and the other three groups were considered as the treated sample, which were exposed to DI water and 30 and 15 wt % oxidative fluid for 48 h, respectively (Figure 3b). These experiments (solid-to-fluid ratio 1:20 g/mL) were conducted at room temperature in an open system. All the cubes were dried at 60 °C for 48 h prior to the characterization of dissolution structure. Porosities of untreated and treated shale cubes were measured by mercury intrusion porosimetry (MIP) and the corresponding pore size distributions (7−100 000 nm) were characterized by mercury injection capillary pressure (MICP). The mercury injection instrument used in this study was a Quantachrome Poremaster 60GT. Meanwhile, another shale cube in each group was further cut into a subsamples (0.5 cm × 0.5 cm × 0.5 cm) and then polished to produce a flat surface using broad argon-ion beam (BIB) in a GATAN, PECS

Figure 3. Flowchart of experimental procedure. a: Spontaneous imbibition of oxidative fluid into shale plugs was performed. b: Measurements of pore volume and the porosity for the untreated and treated samples were performed on shale cubes. c: Crushed shale samples were used to explore the mechanism of oxidation-induced pores and microfractures. C


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Figure 4. Normalized volume of imbibed DI water and 15 wt % oxidative fluid for samples LY-1 (a, b), LY-2 (c, d), and LY-3 (e, f). a, c, e: Imbibed volume vs time; b, d, f: Imbibed volume vs sqrt time. The trendlines show the imbibition rate in different phases. mobility was converted into zeta potentials utilizing Smoluchowski’s formula.58 2.3.4. Swelling Test. Considering that hydration forces have an important effect on the propagation of microfractures,31 the hydration swelling rates of crushed shale samples before and after oxidative treatment were measured by a CPZ-2 NPT double channel expansion meter. Prior to the measurement, the samples were dried at 60 °C for 48 h.

in only two phases, and the imbibition rate during each phase is also very linear with respect to sqrt time, consistent with that reported by Roychaudhuri et al. and Makhanov et al. They reported that the water uptake in shale has two phases for the samples with microfractures or only one phase for the matrix. For the former, phase 2 is quite linear and the slope of the line is much less than that in phase 1.8,20 Similarly, Al-Arfaj et al. reported that three regions were identified during the water imbibition into shale rock.21 This new phase, representing a transition from region 1 to 3, indicates the primary stage of water absorption of clay minerals, but its slope is decreasing. Besides, the osmosis effect may also exist but is ignored in this study.29,59 The results show the S characteristic of normalized imbibed volume vs sqrt time curve. This can be interpreted as follows: In the first period, with time, the oxidative fluid completely and rapidly enters and fills the microfracture network of sample. Capillary forces within the microfracture network of the sample dominate the imbibition during this phase. At the same time, organic-rich shale and oxidative fluid interact continuously, which plays a significant role in oxidation-induced pores and microfractures. With the increase in the imbibed volume of

3. RESULTS AND ANALYSIS Using the imbibition experiments, the imbibition curve was first characterized. The observed DI water and oxidative fluid uptakes of these plugs (LY-1, LY-2, and LY-3) are shown in Figure 4a, c, e plotted as a function of time, indicating that the effect of oxidation on improving the imbibed volume is remarkable with time. Clearly, the oxidation-induced microfractures change the imbibition pathway of shale plugs, thus directly affecting the normalized imbibed volume (Figure 5). Additionally, the normalized imbibed volume gain of these plugs has some variations as a function of the square root of time (sqrt time), as shown in Figure 4b, d, f. The imbibition of oxidative fluid occurs in three different phases, each with its own distinct slope. However, the imbibition of DI water occurs D


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Figure 5. Change in shale plug surface with time during the imbibition of 15 wt % oxidative fluid.

oxidative fluid and oxidation time, the samples experience the propagation of microfractures until rupture at a relatively slow rate (Figure 5). Correspondingly, the slope of the line in phase 2 is increased and clearly more than that in the other two phases (Table 2). This can be attributed to the changes in

(defined as normalized volume of imbibition per unit time) is only 0.0037 per h. The experimental data shows that the weight loss of the plug after imbibition of oxidative fluid for 12 h is 0.1404 g. Oxidation decreases the weight of shale sample, leading to a low measured normalized imbibed volume compared with the actual value. Subsequently, the curve shows a sharp “phase step” owing to a stronger chemical reaction than before, and average imbibition rate increased up to 0.0242 per h during the period of 6.5−7 h. Soon after, this phenomenon occurred again but relatively weakened, and the average imbibition rate is 0.0190 per h during the period of 9− 9.5 h. Similarly, Sun et al. selected Marcellus gas shale samples to conduct the brine imbibition experiment and found the curve of normalized imbibed volume vs time shows a “pulse” phenomenon.28 Clearly, the initiation of microfractures significantly increases the imbibition rate.24 Figure 6 also shows the oxidation-induced microfractures on the plug YL-4 after imbibition of 30 wt % oxidative fluid and confirms that sample rupture was caused by the oxidative fluid of high concentration, compared with DI water. Consequently, these may be used to explain and certify the phase step of the imbibition curve.61

Table 2. Slope of Line in Different Phases during the Imbibition slope

plugs LY-1

LY-2

LY-3

experimental fluid

phase 3

normalized cumulative imbibed volume

0.67

0.08 0.22

0.0459 0.0610

0.58 0.49

0.72

0.10 0.18

0.0499 0.0625

0.55 0.47

0.76

0.10 0.15

0.0521 0.0646

phase 1 phase 2

DI water 15 wt % oxidative fluid DI water 15 wt % oxidative fluid DI water 15 wt % oxidative fluid

0.47 0.43

4. DISCUSSION 4.1. Role of Oxidation in Spontaneous Imbibition. Oxidation-induced pores and microfractures are probably quite important influencing mechanisms of spontaneous imbibition for organic-rich shale. The previous section showed the S characteristic of normalized imbibed volume vs sqrt time curve for the lower mass concentration of oxidative fluid (15 wt %). Even more, the rapid occurrence of microfractures due to a higher mass concentration of oxidative fluid (30 wt %) mainly explains the phase step of the curve. Nevertheless, the specific mechanism should be discussed further. Following the proposed model of Handy, Schembre and Kovscek derived an expression combining the functions of permeability (K), saturation (S), and capillary force (Pc) of a porous medium as

60

samples structure. With the exhaustion of the oxidizing agent in the oxidative fluid, the effect of oxidation-induced pores and microfractures gradually decreases. Then the fluid is continuing imbibed into the sample matrix in a much slower phase until the available pore volume is completely filled. In the last phase, even though the capillary force is still pretty high, oxidative fluid uptake slows down due to significantly lower permeability of sample matrix.20 To further evaluate the effect of oxidative fluid concentration on imbibition behavior, a high concentration was selected and the imbibition time was shortened to test again. Figure 5 shows that the curve of 30 wt % oxidative fluid is relatively lower than that of DI water in the first 6 h, and average imbibition rate E


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Figure 6. Normalized volume of imbibed DI water and 30 wt % oxidative fluid for shale plug LY-4. Note that the phase step of volume imbibed corresponds to the induced microfractures.

expressed by eq 1.62 Makhanov et al. called the product of PcKwSw “imbibition potential” and provided eq 2 as the definition.63 Takahasi and Kovscek proposed a model with matrix and fracture interaction for spontaneous countercurrent imbibition in low-permeability siliceous shale rocks.64 In this study, a modified version of eq 2 was used, where the porosity term was transferred to the left side of eq 2: ij 2P ϕK S A 2 yz Q w2 = jjjj c w w c zzzzt μw k {

and pore size. As for the wettability, the composition of shale sample including quartz, feldspar, dolomite, and clay minerals are hydrophilic, but the OM is hydrophobic. Thus, the organicrich shale is oily or mixed wet in nature.65 With the oxidative decomposition of OM, the inhomogeneity of wetting and continuity of wetting surface in pore will be improved. However, Figure 7 clearly shows an increase of the nanoscale

(1)

where, Qw is the volume of water imbibed; μw is the water viscosity; Ac is the contact surface area; Pc is the capillary force of porous medium; Kw is the water permeability; Sw is the water saturation; φ is the porosity; and t is the time. λ 2μw

PcK wSw =

2ϕAc2

(2)

Q

where, λ = wt ; the slope of the line is obtained by plotting the measured weight of imbibed liquid vs sqrt time; PcK wSΔwϕ = ηλ2

where, η =

μw 2Ac2

Figure 7. Pore volume distributions calculated from MICP of untreated and treated shale cubes.

(3)

pore volume, especially for pore sizes in the range 20−326 nm, indicating the increase in pore size or generation of more oxidation-induced pores. Unfortunately, the change in capillary force is still uncertain in this study. To match the data of pore size distribution obtained by MICP, the porosities of untreated and treated shale samples are measured by MIP. Taking the 15 wt % oxidative fluid as an example, Table 3 indicates that the

is approximately considered as a constant; SΔw

= Sw − Swi; and Swi is the initial fluid saturation. The imbibition potential for shale rock/oxidative fluid was determined by introducing the slope of the line, which was obtained by plotting the measured normalized imbibed volume vs sqrt time. A typical spontaneous imbibition potential curve of DI water considered as the contrast standard is shown in Figure 4. Table 2 summarizes the quantitative results of slope in different phase; the slope in phase 2 is unusually larger than that in phase 1. This can be attributed to the changes in sample heterogeneity caused by the oxidation, such as the tortuosity, microfractures, and pore-size distribution.60 Therefore, we intend to analyze the reason why the slope in phase 2 is increase by eq 3, which is modified based on eq 2. Because the change in oxidative fluid viscosity and contact surface area is negligible during the imbibition within a short time, η is regarded as a constant. At a result, the imbibition potential of oxidative fluid is known as the product of PcKwSΔwϕ, and the dynamic change of PcKwϕ owing to chemical reaction is critical in affecting the slope of the line in phase 2. According to the calculation formula of capillary force, during the imbibition of oxidative fluid into the samples, the capillary force is mainly controlled by the change in wettability

Table 3. Comparison of Porosity Calculated from MIP of Untreated and Treated Shale Cubes sample ID

untreated

DI water

15 wt % oxidative fluid

30 wt % oxidative fluid

porosity,%

5.57

5.09

7.60

7.84

amount of porosity generated by the oxidation process is about 36.4% more than that of the untreated. Since the significant fine scale pore volume in these shales cannot be accessed by mercury, the porosity and grain density may be systematically underestimated by MIP.18 Ge et al. conducted a study and found that the imbibition capacity increases with the shale rock porosity increase.66 On the other hand, Figure 5 shows the macroscopic rupture of samples during the imbibition of oxidative fluid. Similarly, a large amount of the dissolution pores is shown at the micrometer scale in Figure 8. Moreover, F


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Figure 8. SEM images of shale samples before and after exposure to 15 wt % oxidative fluid for 48 h. a: Untreated sample. b: Treated sample. c: Area covered by the yellow box in part b observed at a relatively higher magnification.

Table 4. Mineral Composition of Samples before and after Oxidation by XRD Analysis sample

sum

quartz (SiO2)

feldspar (K[AlSi3O8]/Na[AlSi3O8]

clay mineral

calcite (CaCO3)

dolomite (CaMg(CO3))

pyrite (FeS2)

untreated, % treated, %

100.0 100.0

46.3 60.0

8.0 9.0

32.4 30.7

5.3 0.0

5.4 0.3

2.6 0.0

This may indicate that the organic matter intercalated in the clay mineral domain are oxidized and induce the structure failures, releasing these ions;35,69−72 besides, the oxidative decomposition of OM, which occurs in the pores and on the mineral surface, can also lead to this result.70 However, the mass concentrations of Ca2+, Mg2+, and Fe3+ significantly increased in oxidative fluid, where the concentration ratios before and after the oxidation were 12208, 36, and 3367, respectively. According to the given chemical reaction formulas 4−6 by Chen et al. during the oxidative dissolution of organicrich shale,44 the concentration increase of partly cationic species further confirms the oxidative dissolution of the mineral composition during the imbibition of oxidative fluid.

because the pore-throat distribution obtained from MICP is reflected by the amount of liquid mercury entered, it is indirectly confirms that oxidation may result in a good pore connectivity and even better communication between pores and microfractures. Shen et al. and Zhang et al. reported that fluid permeability of shale samples during the imbibition of water was increased owing to the generation of microfractures.67,68 Therefore, undoubtedly the porosity and fluid permeability of the shale samples were effectively increased by oxidation. Consequently, for the oxidative treatment samples, the larger pores or microfractures are induced during the imbibition of oxidative fluid connecting to the original pore system. This can change the imbibition pathway resulting in an increase of imbibition potential in phase 2. 4.2. Mechanism of Oxidation-Induced Pores and Microfractures. 4.2.1. Dissolution Pores. When an oxidative fluid is imbibed into the pores and microfractures in organicrich shale, the minerals undergo oxidative dissolution. Table 4 shows the results of XRD analysis of the untreated and treated samples. Interestingly, pyrite, calcite, and dolomite were almost completely dissolved. However, the content of quartz and feldspar clearly did not change; a slight increase in their content can be attributed to other factors. Owing to the generation of organic acid or something during the oxidative decomposition of OM and pyrite,44,45 the content of calcite (CaCO3) and dolomite [CaMg(CO3)2] sharply decreased. In addition, the cationic components of DI water and oxidative fluid were compared and analyzed by AAS, in which the crushed shale samples were immersed in these fluids for 48 h (Table 5). DI water mainly had sodium ions (Na+), magnesium ions (Mg2+), potassium ions (K+), and small amounts of ferric ions (Fe3+) and calcium ions (Ca2+). The mass concentrations of K+ and Na+ were increased slightly; meanwhile the content of clay minerals was reduced slightly.

FeS2 + 7.5H 2O2 = Fe3 + + 2SO4 2 − + H+ + 7H 2O

4H+ + CaMg(CO3)2 = Ca 2 + + Mg 2 + + 2H 2O + 2CO2 (5) +

2H + CaCO3 = Ca

K+

Na+

Ca2+

Mg2+

concentration in DI water, mg/L concentration in oxidative fluid, mg/L

8.6

430

0.06

10.0

0.12

23.0

484

716.65

361.6

401.02

2+

+ H 2O + CO2

(6)

Oxidative dissolution of shale components directly affects the pore-size distribution in organic-rich shale. Previous study shows that the pore size of untreated sample is mainly distributed in the range 5−50 nm based on the mercury injection capillary pressure, and the pore volume of unit mass accounts for 71.62% of the total volume. After treatment for 24 h with oxidative fluid, the aperture is mainly distributed in the range 50−500 nm, and the volume of unit mass accounts for 68.44% of the total volume.44 Moreover, oxidative decomposition of OM can contribute to generation of dissolution pores and change in pore-size distribution. Curtis et al. indicated that the OM in shale rock, which can be divided into extractable OM (EOM, or so-called residual bitumen) and solid OM (SOM), is generally regarded as a primary factor controlling the porosity.71 EOM may occupy and block the pores and then dramatically influence the pore structure in thermally low mature or mature shale.73 Li et al. reported that the removal of SOM can effectively strengthen the pore connectivity in shale rock.46 Chen et al. found that the reduction in TOC in the shale sample corresponds to the increase of average pore diameter (defined as the ratio of pore volume to area).44 Figure 9 also shows that the pore sizes of samples are easily increased by oxidation, which may lead to a

Table 5. Cation Composition of Fluid before and after Oxidation by AAS cationic type

(4)

Fe3+

G


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Figure 9. BSE images of shale samples before and after exposure to 15 wt % oxidative fluid for 48 h. Note that SEM observations were performed on the same polished surface. a: Untreated sample. b, c: Treated sample.

high porosity and good connectivity of nanoscale pore networks. 4.2.2. Induced Microfractures. Oxidative fluid can promote and accelerate the lamination and weak structural plane to create microfractures compared with DI water. OM closely contacts brittle minerals and significantly determines the content of clay minerals.72 Oxidative dissolution can severely disrupt the linking force between OM and mineral interface, weakening the linking force between mineral grains, damaging the rock structure, and affecting the mechanical performance.74 This process is different from the acidification of carbonate rock, because the new microfractures are usually located in the organic-rich intervals with a lower high porosity and grain density (Figure 8). Yang et al. showed that a large value of TOC facilitates the propagation of microfractures in organicrich intervals, in which oxidative decomposition of OM will accelerate this process.25 From the perspective of fracture mechanics, oxidative fluid can decrease the rock strength and rock fracture toughness of type I crack, weakening the ability to suppress crack growth.75 Røyne et al. reported that the effect of increasing water on the crack velocity is to lower the threshold energy release rate, which is required for crack propagation.76 Westwood reported that the growth of cracks may be inhibited or promoted by the zeta potential of the chemical solution− rock system.77 When the zeta potential is zero, i.e., the rock surface is charged or electrically neutral, the rate of microfracture propagation increases significantly.57 Figure 10 shows that the oxidative fluid effectively decreases the zeta potential of the shale−water system from −21.50 to −7.14 mv. Therefore, oxidative dissolution combined with clay hydration can lay a foundation for crack initiation.

Further study suggests that the cracks are usually initiated and generated with the collective help of various forces, mainly including clay hydration forces, capillary forces, electric double-layer repulsion, capillary force, and pore pressure.23 Oxidative fluid plays an important role in different stages of crack propagation by influencing these forces as shown in Figure 12. The van der Waals (VDW) attractive force exists between any surfaces. Yoo et al. reported VDW attractive forces have an energy minimum when the interlayer distance is 0.32−0.33 nm.78 The attractive forces operate in the region closest to the crack tip, whereas the strong affinity of water to the fracture surface creates a repulsion further away from the tip.74 To expand the layers, the VDW force between the interlayers is opposed by the repulsive force known as hydration repulsive force. The repulsive force acting on the near-tip region of a water-filled intracrystalline fracture is controlled by surface hydration forces and osmosis hydration forces. This is a significant support for crack propagation.79 Shale belongs to the hydrocarbon source rock, where the vast majority of OM attaches to the clay minerals. Owing to a high specific surface area, clay minerals determine 85% of the OM enrichment conditions, generally existing in the form of mineral−combined OM.71 Zhu et al. showed that once the OM in soil was removed, the area of the clay surface will be increased.72 Thus, oxidative decomposition of OM may increase the contact area between clay minerals and water, promoting the release of hydration forces by increasing the layer spacing and performing swelling (Figure 11). Taking the crystal structure of illite as an example, the hydration forces can reach over 50 MPa at the initial stage of hydration.31 Neuzil and Provost reported that the osmotic hydration forces may exceed 10 MPa in formations with ∼0.2 porosities and even

Figure 10. Change in zeta potential on water−shale interface after exposure to 15 wt % oxidative fluid for 48 h.

Figure 11. Measurement of swelling rate of shale samples before and after exposure to 15 wt % oxidative fluid for 48 h. H


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Energy & Fuels

Figure 12. Diagram of shale microfracture initiation under multiple forces.

Figure 13. Diagram of oxidizing stimulation enhancing the effect of hydraulic fracturing in a shale gas reservoir.

exceed 30 MPa in formations with ∼0.1 porosities.33 Moreover, Table 4 shows the increase in cationic species concentration after the oxidative dissolution, such as Ca2+ and Mg2+, which may have a positive effect on the strength of hydration forces.31 If these forces work together, it may concentrate the stress on the crack tip and increase the stress intensity factor.80 Once the stress intensity factor is higher than the fracture toughness, it will cause the expansion and propagation of cracks. Unfortunately, when the layer spacing is more than 3 nm, the hydration forces disappear as they belong to the shortrange force.31,81 During this period, VDW attraction and electric double-layer (EDL) repulsion of long-range force continue to work on the cracks. The interactions of these two forces can be quantitatively characterized by the famous DLVO theory; therefore, it is also attributed to the category of DLVO forces. The VDW attractive force is not sensitive to the electrolyte concentration and pH of aqueous solution. However, the EDL repulsive force significantly depends on the surface charge and parameters such as electrolyte concentration and pH. Although oxidation leads to a decrease in pH and increase in electrolyte concentration; regrettably, this paper still fails to reveal the change in EDL repulsive force affected by oxidation. Then, the propagation of cracks or microfractures occurs due to capillary force and pore pressure. Makhanov reported that some microfractures are initiated with the imbibition of oil despite having no affinity for adsorption in clays and indicated that some pore pressure, which is developed owing to the imbibed fluid, may be another mechanism apart from clay hydration force inducing microfractures.82 Moreover, during the interaction between organicrich shale and oxidative fluid, some pore pressure develops due to the releases of heat and gas,45 inducing the further propagation of cracks or microfractures.83 As a result, the microfractures and even macroscopic fractures were generated by the coalescence of these cracks.84 Of course, natural microfractures also may propagate in this process.

5. IMPLICATIONS FOR OXIDIZING STIMULATION OF A SHALE GAS RESERVOIR As one of the important technologies for economic production of shale oil and gas, hydraulic fracturing makes micrometer or millimeter microfractures, connecting the nanoscale pores, and then forming a gas transmission channel with a higher permeability.12 The well productivity might be further improved if the hydraulic fractures communicate with the induced and natural secondary fracture networks.85 However, the shale gas in nanoscale pores is still difficult to flow into the fracture network and wellbore, exponentially decreasing gas well production because the gas supply capacity of the shale matrix is far lower than the gas transmission capacity of fractures.86 Therefore, the key to enhancing shale gas recovery is to improve the gas supply of the matrix and natural fractures.45 Oxidation-induced pores and microfractures not only decrease the size of diffusion dominant zones in the matrix but also increase the size of gas transport pathway from the pores into the fractures.44 Therefore, injection of oxidative fluid may play a significant role in chemically stimulating the matrix further; however, enlarging the range of oxidative dissolution is another critical problem. Spontaneous imbibition plays a significant role in promoting the oxidative fluid to spread and distribute in the fracture and matrix.7,19,20 In turn, oxidative fluid can improve the imbibition potential of shale by positively changing the imbibition pathway. What’s more, oxidation-induced pores and microfractures could contribute to shale matrix stimulation. As a result, a coordinative effect between spontaneous imbibition and oxidative dissolution is established, in which the range of oxidizing stimulation is enlarged with the increase in imbibition depth as the oxidation time progresses (Figure 13). Taking into account the engineering geological characteristics of shale gas reservoir development, an oxidative fluid is injected into the conventional fracturing fluid, making full use of the characteristics of OM and pyrite, which are oxidizable to create dissolution-induced pores and microfractures, maximizing the beneficial stimulation effects of the water−rock I


Article

Energy & Fuels interaction. Based on the coordinative effect, the gas supply ability of nanoscale pores and microfractures can be improved and achieve the purpose of long-time stimulation after hydraulic fracturing operation in shale gas reservoirs. However, the imbibition experiments described in this study were carried out on certain shale samples to imbibe the oxidative fluid; this is different from the spontaneous imbibition in the formation. Besides, the adsorbed gas in nanoscale pores and in-situ stress was not considered. These may affect the oxidation-induced pores and microfractures. Regretfully, we still lack the evidence to fully prove the creation of pores and microfractures due to oxidation under the formation conditions. Therefore, more studies on oxidationinduced pores and microfractures and imbibition characteristics under simulated formation conditions are needed in the future.

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dissolution and, then, achieving the oxidizing stimulation of shale formation to enhance shale gas recovery.

AUTHOR INFORMATION

Corresponding Author

*Tel./fax: +86 028 83032118. E-mail address: cqygm@ foxmail.com. ORCID

Qiuyang Cheng: 0000-0001-8785-4735 Notes

The authors declare no competing financial interest.

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ACKNOWLEDGMENTS This work is supported by the National Natural Science Foundation of China (Grant No. 51674209) and Innovative Research Project for Sichuan Youth Scientific and Technological Innovation (Grant No. 2016TD0016). We would like to thank Fansheng Huang and Jian Tian for useful discussions. SEM analyses were conducted in the Shale Gas Evaluation and Exploitation Key Laboratory of Sichuan Province, Chengdu, China. We would like to thank Dr. Dan Lin for SEM imaging.

6. CONCLUSION In this study, imbibition experiments were carried out for an oxidative fluid into the shale samples obtained from the lower Silurian LMX formation in Southeast Chongqing, China. Taking the imbibition behavior of DI water as a reference, the imbibition characteristic of oxidative fluids with mass concentrations of 15 and 30 wt % were evaluated, and the effect of oxidation on imbibition was determined. The samples surface was observed by SEM, and the dissolution pores were quantitatively characterized by MIP and MICP before and after the oxidation to clarify the role of oxidation in spontaneous imbibition. Finally, the mechanism of oxidation-induced pores and microfractures is elucidated by combining the characterization of oxidative dissolution of mineral composition by XRD and AAS, and the process of crack propagation is discussed from the perspective of fracture mechanics. The following conclusions are drawn for the shale evaluated in this study. (1) Oxidative fluid can contribute to a high imbibition rate and imbibed volume compared with the DI water. The imbibition of 15 wt % oxidative fluid shows an S characteristic of normalized imbibed volume vs sqrt time curve with the generation of microfractures; 30 wt % oxidative fluid is beneficial for accelerating the propagation of microfractures and even rupture of the sample, which leads to a significant phase step phenomenon as the normalized imbibed volume vs time curves shows. (2) Oxidative dissolution of shale components not only generates dissolution pores but also induces the initiation and propagation of microfractures by decreasing the mechanical strength, increasing the growth rate of subcritical fractures, and promoting the release of hydration forces of clay minerals. This observation indicates that oxidative dissolution may improve the imbibition pathway and then increase the imbibition potential. (3) Considering the engineering−geological characteristics of shale gas reservoir development, an oxidative fluid can be injected into the fracturing fluid making full use of the chemical effect to create dissolution-induced pores and microfractures, thereby maximizing the beneficial stimulation effects of the water−rock interaction. This provides a solid foundation for increasing the gas supply ability of nanoscale pores and microfractures by the coordinative effect between imbibition and oxidative

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