Experimental Study on the Propagation Characteristics of Hydraulic Fracture in Clayey-Silt Sediments

Lu, Cheng; Qin, Xuwen; Mao, Wenjing; Ma, Chao; Geng, Lantao; Yu, Lu; Bian, Hang; Meng, Fanle; Qi, Rongrong

doi:https://doi.org/10.1155/2021/6698649

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Abstract Introduction Results and Discussion Conclusion Data Availability Conflicts of Interest Acknowledgments References Copyright Related Articles

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Hydrocarbon Migration and Extraction in Tight Formation

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Volume 2021 | Article ID 6698649 | https://doi.org/10.1155/2021/6698649

Experimental Study on the Propagation Characteristics of Hydraulic Fracture in Clayey-Silt Sediments

Cheng Lu,^1,2,3,4,5Xuwen Qin,^1,2,3,6Wenjing Mao ,^1,2,3Chao Ma,^1,2,3Lantao Geng,^1,2,3Lu Yu,^1,2,3Hang Bian,^3,5Fanle Meng,^1,2,3and Rongrong Qi^1,2,3

Academic Editor: Guo Chaobin

Received31 Dec 2020

Revised06 Apr 2021

Accepted29 Jul 2021

Published14 Aug 2021

Abstract

The low permeability of clayey-silt hydrate reservoirs in the South China Sea affects the thermal and pressure conductivity of the reservoir, which is difficult to spread to the far end of the wellbore and achieve commercial gas production. In this respect, enhancing the permeability to assist depressurization is necessary. Hydraulic fracturing is a promising reservoir stimulation method for gas hydrate reservoirs. Up to now, majorities of research focus on the fracability of hydrate-bearing sandy sediments, but the studies rarely involved fracture propagation characteristics of clayey-silt sediments in the hydrate dissociation area. In this paper, three sets of hydraulic fracturing experiments under different confining pressure were carried out using the clayey-silt sediments in the Shenhu Area. Computed tomographic (CT) images indicated that clayey-silt sediments could be artificially fractured, and the fracturing fluid could induce tensile fractures and local shear fractures. A multimorphological fracture zone occurred near the borehole. Furthermore, the greater the confining pressure imposed, the greater the breakdown pressure was, and the microfracture arose more easily. The fractures at the top were generally wider than those at the bottom with the same confining pressure. The experimental results could reveal the fracture initiation and propagation mechanism of clayey-silt sediments and provide theoretical support for hydraulic fracture in the hydrate dissociation area.

1. Introduction

Natural gas hydrates are crystalline material formed by natural gas and water at high pressure and low temperature. Its global resource is estimated that more than twice the total amount of proven traditional fossil energy resources [1–4]. However, 90% of the gas hydrates in nature exist in marine clayey-silt or silt sediments [5–7], with characteristics of low formation temperature, weak cementation, nondiagenesis, and low permeability [8–13]. There could be a potential risk for methane leak, sand production, stratum settlement, and so on in long-term exploitation, which greatly limits the hydrate productivity [5, 14, 15]. So far, the natural gas hydrate reservoir production tests imply that the gas production via depressurization is still far from reaching the commercial level [16–19].

Yu et al. [20] adopted the special production strategies of aggressive depressurization and permeability improvement and conducted long-term numerical simulations to contrast the gas recovery enhancement with different production strategies. They concluded that the permeability improvement, which raised the average gas production rate by one order of magnitude, might be more reliable than the aggressive depressurization on the gas recovery enhancement. Hence, enhancing the permeability to assist depressurization is necessary [21–25].

Hydraulic fracturing is an effective stimulation method for increasing the permeability in unconventional resources. It could create artificial fractures in gas hydrate layers, strengthen the seepage capacity between wellbore and dissociation boundary, accelerate pressure propagation, improve thermal transfer efficiency [14, 26, 27], and enlarge the hydrate dissociation area so as to promote gas and water to rapidly flow to the wellbore through fractures and enhance well production of low-permeability reservoirs (Figure 1).

To understand the fracture propagation characteristics of hydrate-bearing sediments, laboratory and numerical studies have been conducted [28–32]. Konno et al. [28] combined hydraulic fracturing triaxial experiment and X-CT scanning to investigate fracture behavior. They found that the permeability of unconsolidated sandy sediments could be improved significantly due to crystal-crystal and crystal-sand boundaries activated by hydraulic fracturing. Too et al. [29] utilized a thin circular plastic sheet to form natural fracture and indicated that laboratory synthesized hydrate-bearing sandy sediments with the saturation of 50-75% could create new fractures and propagate the natural fractures. Liu et al. [30] built a novel feasibility evaluation model of hydraulic fracturing in hydrate-bearing sediments and indicated that higher fracturing fluid displacement would produce greater flow resistance to improve gas production. Previous studies that have verified brittleness index, mineral composition, hydrate saturation, fracturing fluid viscosity, and displacement are the main factors affecting the fracability of hydrate-bearing sediments [28–30]. Hydrate-bearing sandy sediments may form a cementing structure at higher saturations to possess consolidated rock-like mechanical properties due to the interconnected network of hydrates in pores or hydrates on sand grains [27, 31]. Thus, hydrate-bearing sandy sediments could be artificially fractured using hydraulic fracturing [32].

Up to now, majorities of research focus on the fracability of hydrate-bearing sandy sediments, but the studies rarely involved fracture propagation characteristics of clayey-silt sediments in the hydrate dissociation area. The formation energy depletes at the later stage of hydrate gas production, causing the decline in thermal and pressure conductivity of the reservoir, which is difficult to spread to the far end of the wellbore [33–35]. Meanwhile, lack of gas channel to flow from the dissociation front to the wellbore, the gas production is seriously affected [36–39]. Therefore, the fracture propagation characteristics of clayey-silt sediments in hydrate dissociation are an important issue.

Ito et al. [40] used silica sand mixing kaolinite flour as laboratory synthesized samples to analyze hydraulic fracturing behavior in unconsolidated sands and indicated that fracturing fluid injection would create the fractures between the sand and the mud layers. Zhang et al. [41] experimentally investigated the influence of fracturing fluid viscosity on hydraulic fracturing and observed that high-viscosity fracturing fluid could induce higher breakdown pressure and complex fractures. Yang et al. [42] conducted a laboratory fracturing test in clay sediments to observe fracture propagation. They investigated that the vertical and horizontal fractures expanded synchronously and did not indicate significant directivity without confining pressure and overburden pressure. The high-pressure fluid penetrated the cavities in the clay sediments, forming areas of locally high pressure owing to the low permeability of clay sediments. As mentioned above, the laboratory fracturing test is an effective and direct method for analyzing fracture propagation mechanism. However, revealing the spatial distribution of fractures should combine with other methods.

This paper carried out hydraulic fracturing experiments to analyze the fracability of clayey-silt sediments in the hydrate dissociation area of the Shenhu Area under different confining pressure. The influence of the confining pressure on fracture initiation and propagation was discussed based on CT scanning. The results provide theoretical support for the research on hydraulic fracturing in clayey-silt sediments of the hydrate dissociation area.

2. Samples and Experiment Method

2.1. Samples

The tested samples composed of clayey-silt sediments with a median particle size of 12 μm are from the surface of the seabed in the Shenhu area. Clay and quartz are dominant, which account for 47.2% and 36.4%, respectively. The clay minerals are mainly montmorillonite and illite [19, 37].

The particles with a diameter of 0.005 mm-0.05 mm account for about 80%. Figure 2 shows the stress-strain relationship of clayey-silt sediments that belongs to plastic failure. When the strain reaches 2%, the undrained shear strength reaches the peak value. When the strain exceeds 2%, the stress basically does not increase or slightly decreases. The effective cohesion and internal friction angle account for 0.04 MPa and 0.5°, respectively [43, 44].

2.2. Apparatus

A schematic of hydraulic fracturing equipment is shown in Figure 3. The equipment mainly consists of core gripper, fracturing pipe, fluid supply system, overburden pressure system, confining pressure system, and data acquisition system [45]. Table 1 presents the details of the equipment parameters. The fracturing fluid is injected via the HAS-200 pump. Uniform radial pressure and axial pressure are possessed to simulate in situ stresses.

Fluorescent paint with a viscosity of 70 mPa·s was selected as fracturing fluid, which could be filled in fractures after drying to increase the discernibility of fractures. During the experiments, three sets of samples were designed. The samples sizes were , , and , respectively.

Dry clayey-silt sediments were compacted in the core gripper by the stick to produce the core sample with the porosity derived by the mass balance of 39% (Figure 4). To prevent pipelines from being blocked by the samples, the wire mesh and asbestos paper were placed on the inner wall of the core gripper. Then, the confining and overburden pressure was maintained constant as Table 2. The fracturing fluid was injected into the core gripper at a speed of 10 ml/min. After fracturing, the core gripper without the pipeline was put into the oven at a temperature of 50°C to help the fracturing fluid to fill in the fractures for convenient observation and avoid more fractures caused by sample dehydration. Meanwhile, low temperature drying is an effective method for taking out the sample to maintain the integrity of fractures. Finally, the samples were scanned by a CT scanner (NeuroLogica Corporation, CereTom) to detect the fractures with a resolution of and a single exposure time of 0.5 s. The three-dimensional gray-scale images were processed by collecting the X-ray attenuation information to obtain the segmentation image via Avizo software that could be utilized for fracture network modeling. Then, the fracture information was extracted based on the ball-stick model to reveal the spatial distribution of fractures, as shown in Figure 5 [39, 46]. Especially, note that the fractures with smaller widths should not be in the study since the sample heating will produce some fractures.

3. Results and Discussion

3.1. Fracturing Behavior with Confining Pressure of 10 MPa

The injection pressure curve reflects the fracturing behavior in clayey-silt sediments. Figures 6(a) and 6(b) show the injection pressure changes for two samples during hydraulic fracturing. The injection pressure rapidly increased for short injections to a peak and then drop to a plateau, which indicates that hydraulic fractures and microfractures were induced. The breakdown pressure of samples 1 and 2 was approximately 11.5 MPa and 11 MPa, respectively. Owing to the low permeability of the samples, the injection pressure fluctuated constantly in the process of hydraulic fracturing.

(a)

(b)

(c)

Several fractures were induced by hydraulic fracturing in clayey-silt sediments. A main fracture was in the center of the sample and propagated through the entire sample with a width of 6 mm. Some discontinuity fractures could be observed on the side of the sample, as shown in Figure 7.

The fracture morphology of the samples by CT scan was utilized to further analyze the fracture initiation and propagation mechanism of clayey-silt sediments. Three horizontal fractures were formed at the top of sample 1 with a length of 6.5 cm, and the width was 3.76 mm, 4.26 mm, and 4.51 mm, respectively, while the width of the fractures at the bottom of the sample was 6 mm, 6.5 mm, and 7.5 mm, respectively, as shown in Figure 8(a).

The vertical fracture of sample 1 propagated, connected, and communicated the branched fractures and microfractures induced by shear failure near the wellbore. Hence, the propagation and widening alternated to form a high-density fracture zone (Figure 8(b)). At the same time, several continuous horizontal fractures were observed around the wellbore, connected the microfractures, which showed an abnormal increase in the width of some fractures (Figure 8(a)). Due to the natural fractures by uneven sample filling, some new initial stresses might generate on the original propagation. If the induced stress exceeded the corresponding rock strength, a turning fracture might be formed (Figure 8(c)).

Three horizontal fractures were formed at the top of sample 2 with a length of 6.5 cm, and the width was 2.2 mm, 2.09 mm, and 5.6 mm, respectively, while the width of the fractures at the bottom of the sample was 3.26 mm, 3.16 mm, and 4.1 mm, respectively, as shown in Figure 9(a). Due to the high plasticity of the clayey-silt sediments, branching off often appeared in shear failure occurred. And the branched fractures propagated to the side of the sample (Figure 9(b)). At the same time, several horizontal fractures and fracture zones could be observed around the wellbore. However, lack of energy in the lower sample, microfractures were hard to connect and communicate with each other, which could not merge with the main fracture to distribute in the sample independently (Figure 9(c)).

3.2. Fracturing Behavior with Confining Pressure of 15 MPa

Figure 6(c) demonstratesthat the injection pressure rapidly rose at the peak of 21.7 MPa, then decreased slightly and finally stabilized at approximately 20 MPa. Additionally, in contrast to cases with low confining pressure, the breakdown pressure of sample 3 is higher than that for samples 1 and 2, which indicated that sample 3 required more energy to exceed the compressive strength increasing with confining pressure.

Three horizontal fractures were formed at the top of sample 3 with a length of 6.5 cm, and the width was 10.5 mm, 3.2 mm, and 5.6 mm, respectively (Figure 10(a)). The vertical fracture of Sample 3 deflected at a certain angle near the wellbore (Figure 10(b)). Independent fracture could be observed around the wellbore. The horizontal fractures in the lower sample with short extended length were poorly developed, which could not penetrate the sample. Therefore, only two horizontal fractures could be observed at the bottom of sample 3 (Figure 10(c)).

Due to the high plasticity of clayey-silt sediments, fracturing fluid leakage was small, which produced an expansion pressure. The shear failure occurred at the tip of the tensile fracture. After the shear expansion, the fracturing fluid continued to penetrate. The permeable zone often became shear a failure zone.

3.3. Discussions

Previous studies indicate that the complexity of fracture geometry has a great relationship with the rock brittleness in hydraulic fracturing [47–49]. As the brittleness increases, the hydraulic fracture geometry becomes more complex [50]. And as brittleness decreases, the fracture becomes more like biwing fracture geometry. Clayey-silt sediments are high in content of clay mineral swelled with water to greatly enhance the reservoir plasticity, resulting in more energy consumption in the formation to propagate and generate multiple fractures.

The mechanical characteristics of the reservoir have a significant influence on fracture pressure, fracture width, and tensile shear failure mechanism, while the pore pressure gradient is the dominant factor controlling the fracture half-length and the influence degree of shear failure [31, 41]. Due to the low permeability of clayey-silt sediments, the injected fracture fluid easily maintains the high pressure near the wellbore. When the injection pressure is greater than the breakdown pressure, the samples begin to generate fractures. Additionally, clayey-silt sediments near the wellbore are prone to plastic yield, and the stress concentration is weakened, which are affected by plasticity and fluid leak-off. Therefore, tensile and shear failure occurs simultaneously during fracture initiation. By the invasion of fracture fluid and the increase of pore pressure, shear failure occurs at the fracture tip, and then the fracture tip fails subjected to tensile stress, resulting in the propagation of clayey-silt sediments.

The initial stress of fracture propagation is generated different from that of the original path affected by the heterogeneity and the existence of internal weak structural plane, At the same time, the friction between fracturing fluid and clayey-silt particles also causes lots of subtle shear failure in the fracture propagation process, resulting in the fracture instability to form turning fractures or even multibranched fractures, and microfractures, and fracture zones can be observed around the main fracture. And the fracture surface becomes rougher with a small number of sediment particles peeling off.

To obtain the fracture information accurately, the width of the samples was analyzed by using the ball-stick model, as shown in Figure 11. When the confining pressure was 10 MPa, the fracture width ranged from 0 mm to 7.5 mm, and three peaks were 1.2 mm, 2.5 mm, and 3.4 mm, respectively. The fractures with a width of 1.2 mm-3.4 mm accounted for 68% of the fracture volume (Figures 11(a) and 11(b)). When the confining pressure was 15 MPa, the fracture width ranged from 0 mm to 6.5 mm, and the peaks of the curve obviously shifted to the right, which were 1.9 mm, 3.6 mm, and 5.6 mm, respectively. The fractures with a width of 1.9 mm-5.6 mm accounted for 77% of the fracture volume (Figure 11(c)). The increasing width indicated that the hydraulic fracturing effect of fracturing fluid on fractures was enhanced continuously with the confining pressure.

(a)

(b)

(c)

0 mm-2 mm fractures with high confining pressure accounted for 31% of the total volume, while 0 mm-2 mm fractures with low confining pressure only accounted for 13% of the total volume, which indicated that the plasticity of clayey-silt sediments with high confining pressure was stronger, and plastic expansion occurred easily. In the hydraulic fracturing process, the sediments near the wellbore were continuously squeezed, and plastic deformation occurs to generate numerous microfractures.

Under the same confining pressure, the fractures at the top were generally wider than those at the bottom, and the width was mainly 1.2 mm-6 mm (Figure 12(a)). In contrast, the width of the fracture at the bottom was mainly 1 mm-5 mm. Additionally, the curve crest obviously shifted to the left (Figure 12(b)), which might be the result of lack of energy in the lower sample. Microfractures were hard to connect and communicate with each other to form wider fractures.

(a)

(b)

4. Conclusion

The hydraulic fracturing experiments were conducted to analyze the fracability of clayey-silt sediments in the hydrate dissociation area of the Shenhu Area under different confining pressure. The fracture behavior as a consolidated rock-like fracturing mode was observed. Owing to the high content of clay mineral swelled with water to greatly enhance the reservoir plasticity, formation requires more energy consumption to propagate and generate tensile fractures and local shear fractures. The plasticity of clayey-silt sediments with high confining pressure is stronger, and plastic expansion occurs easily. When the confining pressure was 15 MPa, the fractures were mainly composed of 1.9 mm-5.6 mm wide fractures, accounting for 77% of the total volume. When the confining pressure was 10 MPa, the fractures were mainly composed of 1.5 mm-3.4 mm wide fractures, accounting for 68% of the total volume. The fracture width increases with the confining pressure.

The influence of the confining pressure on fracture initiation and propagation based on CT scanning in this paper could serve as a reference in the research on hydraulic fracturing in clayey-silt sediments of the hydrate dissociation area. It is noted that the effect of low temperature and fracture fluid is not taken into account in this paper. Thus, some of the future considerations relating to the fracability of clayey-silt sediments may include examining the (1) effects of low temperature to simulate closely to the real application (2) effects of fracture fluid and proppant and (3) larger studies to observe more fracture propagation behaviors.

Data Availability

The data used to support the findings of this study are available from the corresponding author upon request.

Conflicts of Interest

The authors declare that they have no conflicts of interest.

Acknowledgments

The authors are grateful to the National Natural Science Foundation of China (51991365), Key Special Project for Introduced Talents Team of Southern Marine Science and Engineering Guangdong Laboratory (Guangzhou) (GML2019ZD0105), Key Program of Marine Economy Development (Six Marine Industries) Special Foundation of Department of Natural Resources of Guangdong Province [2020]047, and China Geological Survey Project (DD20211350).

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Copyright © 2021 Cheng Lu et al. This is an open access article distributed under the Creative Commons Attribution License, which permits unrestricted use, distribution, and reproduction in any medium, provided the original work is properly cited.

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