Feasibility evaluation of hydraulic fracturing in hydrate-bearing sediments based on analytic hierarchy process-entropy method (AHP-EM)

https://doi.org/10.1016/j.jngse.2020.103434Get rights and content

Highlights

  • Fracability of hydrate was analyzed based on theory analysis and experiments.

  • Hydrate with high fracability index is favorable for hydraulic fracturing.

  • Increasing fracturing fluid viscosity improves fracability of hydrate.

Abstract

Natural gas hydrate is an attractive potential as alternative energy source. The initial studies of natural gas hydrate production test have shown that the hydrate productivity via conventional depressurization is still far to reach the commercial level, hence, hydraulic fracturing has been proposed to stimulate the hydrated formation to enhance production. However, the buried depth of hydrate-bearing sediments is generally shallow, and the cementation of sediments is weak. Whether the hydrate-bearing sediments has adequate and commercially viable fracability is a question yet to be answered. In this study, a novel feasibility evaluation model of hydraulic fracturing in hydrate-bearing sediments is developed based on analytic hierarchy process-entropy method. The fracability index is proposed to evaluate the fracability of hydrate-bearing sediments. Representative samples were built based on the physical and mechanical characteristics of Alaska permafrost, and hydraulic fracturing experiments were carried out to evaluate the feasibility of hydraulic fracturing as a stimulation technique. The results showed that the hydrate-bearing sediments with fracability index >0.72 can form fractures under different fracturing fluid viscosity ratio. For hydrate-bearing sediments with fracability index <0.39, when the fracturing fluid viscosity ratio is 1, no fracture network is formed during hydraulic fracturing. However, when the fracturing fluid viscosity ratio is increased to more than 120, fractures may develop. For the hydrate-bearing sediments with fracability index between 0.39 and 0.72, the results are not promising when fracturing fluid viscosity ratio is 1, however, when fracturing fluid viscosity ratio is more than 120, fractures observed to grow. In general, the results indicate that the samples with high fracability index are sweet spots in hydrate sediments in terms of fracability. At low fracability index values, the viscosity of fracturing fluid has a key role in fracability, where increasing the viscosity will result in higher fracability index.

Introduction

Natural gas hydrate is a kind of crystal compound formed by natural gas and water in the environment of low temperature and high pressure, which is widely distributed in permafrost or seabed sediments. Compared with traditional fossil fuels such as oil and natural gas, it has higher energy efficiency and more abundant reserves (Zheng et al., 2018a, Zheng et al., 2018b). According to scientific speculation, the reserves of natural gas hydrate are 2 times of the total amount of coal, oil and natural gas that have been proved at present, and it is the key development object of clean energy in the future (Song et al., 2014; Chong et al., 2018).

At present, depressurization method is mainly used to develop the hydrate formation, using the bottom-hole pressure drop to destroy the stable state of hydrate and make it decomposed (Zheng et al., 2018a, Zheng et al., 2018b; Chong et al., 2017; Yang et al., 2017). However, there are two disadvantages associated with this method. One is that the bottom-hole pressure drop has a limited range. The decomposition of hydrate is a dynamic process and is endothermic, which can easily cause the secondary formation of hydrate in the deep formation. Secondly, the porosity of hydrate formation decreases rapidly with the increase of hydrate saturation, which is not conducive to the flow of fluid after hydrate decomposition.

Up to now, just eight trial-production tests have been carried out on the hydrate reservoir worldwide, and only Mesoyaha (Russia) hydrate reservoir has realized commercial development by means of depressurization. All the other trial-production tests cannot achieve commercial development by depressurization. (Chen et al., 2018; Yu et al., 2019; Li et al., 2016). Therefore, how to increase the range of depressurization and provide the effective flow passage after the decomposition of hydrate are the key questions to answer in hydrate development.

Hydraulic fracturing technology has been widely used in the development of oil and gas reservoirs (Liu et al., 2019a, Liu et al., 2019b). As a potential technology, hydraulic fracturing has been proposed by pre-scholars to stimulate the hydrated formation and enhance the hydrate production (Feng et al., 2019; Sun et al., 2019; Wang et al., 2018; Chen et al., 2017). The artificial fracture network formed by hydraulic fracturing can effectively expand the bottom-hole pressure range, and the artificial fracture has a high conductivity, which can be used as an effective flow passage of fluid. At present, the research on hydraulic fracturing of hydrate-bearing sediments is at its initial stage. T. Ito et al. (2008) carried out experimental studies of hydraulic fracturing in unconsolidated sandstones for methane hydrate production (Ito et al., 2008). They used silica sand mixing kaolinite flour to form matrix of samples without hydrate, and examined phenomena caused by injecting fluid through the samples with tri-axial compressive stresses. Strictly speaking, the experiment cannot truly reflect the fracture propagation mechanism in hydrate formation because there is no saturated hydrate in the rock sample. Y. Konno et al. (2016) reported on laboratory studies of hydraulic fracturing in hydrate-bearing sand samples. The results showed that the injection pressure rapidly increased after the start of fracturing fluid injection, but suddenly decreased afterward. X-ray computed tomography revealed that laminar fractures were generated after this pressure drop. The study indicated that hydraulic fracturing is a promising stimulation method to enhance hydrate production. Too et al. (2018a, b) presented experimental data to determine the apparent fracture toughness corresponding to a hydraulic fracturing propagating as a penny-shaped crack in a frozen sand. Hydraulic fracturing experiments were conducted on the synthesized high saturation methane hydrate-bearing sand specimens (approximately 50–75%) to examine the susceptibility of hydraulic fracturing in methane hydrate formation. Zhang et al. (2020) performed a series of tri-axial hydraulic fracturing experiments on methane hydrate-bearing sediments to analyze the influence of fracturing fluid viscosity and consolidate strength on fracturing effect. The fracturing results were dominated by the fracturing fluid and the mechanical properties associated with pressure and temperature. Liu et al. (2020) manufactured three types of samples (sediment skeleton samples, hydrate sediment samples and hydrate-ice sediment samples) based on the sedimentary layer of Chinese South Sea and carried out hydraulic fracturing test using these samples. The results showed that the fracture propagation was affected by fluid pressure and thermal stress. Increasing the fluid injection time resulted in hydrate decomposition, which was unfavorable to hydraulic fracturing. Liu et al. (2020) proposed fracturing and filling sand control method to address the wellbore collapse and sand production during hydrate production. An analytical model was developed to analyze the initiation and propagation of multiple fractures in horizontal wells. This method is mainly to form a short fracture around wellbore with sand filling to control the sand production, which is significantly different from the conventional hydraulic fracturing. Desilva et al. (2019) proposed a new hydrophobic non-explosive demolition agent as a rock fracturing technique, which is quite different form conventional hydraulic fracturing. The laboratory tests showed the density of the gradually generated rock mass fractures increased with confining pressure and pore fluid salinity.

The possibility of creating artificial fractures in synthetic hydrate-bearing sediments may present an opportunity to improve the gas production from natural occurring hydrate-bearing sediments. However, the buried depth of hydrate-bearing sediments is generally shallow, and the cementation of sediment is weak. Besides, hydrate has cementation effect on rock particles. If hydrate phase equilibrium is destroyed during hydraulic fracturing, hydrate will decompose, which will reduce the sediment cementation (Madhusudhan et al., 2019; Yoneda et al., 2016; Dong et al., 2018). Therefore, it is important to examine the fracability of the hydrate-bearing sediments to determine whether hydraulic fracturing can be a potential enhanced recovery method for such reserves or not.

At present, several fracability indices has been proposed in shales based on different parameters, but there is no widely accepted and standard index. In overall, the general understanding was that the larger the brittleness index the better the reservoir formation will be for fracturing (Wang et al., 2015; Zhang et al., 2016; Li et al., 2018). However, further studies showed that this may not be generalized to all cases and there are additional factors that may also influence the fracability (Bai et al., 2016). Sun et al. (2015) considered fracture toughness in evaluation of fracability index. Fracture toughness is the ability of absorbing energy in the process of rock fracture. The reservoir with high fracture toughness is not suitable for hydraulic fracturing. Yuan et al. (2013) evaluated the fracability index with respect to brittleness, fracture toughness and rock mechanical properties. Tang et al. (2012) considered the influence of mineral composition and natural fractures on hydraulic fracturing and evaluated the fracability as a function of brittleness index, quartz content, natural fractures and diagenesis. As a brittle mineral, quartz is prone to easily fracture, so a reservoir with high quartz content is more suitable for hydraulic fracturing. Natural fractures can be connected with hydraulic fractures to form a complex fracture network and increase the stimulated reservoir volume (SRV). Wang et al. (2016) further considered the influence of stress anisotropy and proposed an evaluation method composed of brittleness index, fracture toughness, natural fracture, diagenesis and stress anisotropy.

As discussed above, the fracability indices, in general, have been developed as a function of rock brittleness, fracture toughness, diagenesis, natural fracture, mineral composition and stress anisotropy. For hydrate-bearing sediments, the hydrate plays a key role in cementation of sediment particles. Different hydrate saturation will affect the physical properties and cementation, so hydrate saturation is an important factor in hydraulic fracturing evaluation of hydrate-bearing sediments. The buried depth of hydrate-bearing sediments is generally shallow, and the hydrate mainly exists in sediment pores without natural fractures. Therefore, hydrate saturation, brittleness, stress anisotropy and mineral composition were considered in this study to develop a novel fracability index of hydrate-bearing sediments based on analytic hierarchy process-entropy method (AHP-EM). Ten hydrate-bearing sediments samples were constructed based on the physical characteristics of Alaska permafrost, and hydraulic fracturing experiments were carried out for the purpose of this study. The process of feasibility evaluation of hydraulic fracturing in hydrate-bearing sediments are shown in Fig. 1, and the detailed of this study and the results are presented in the following sections.

Section snippets

Fracability index parameters

The four parameters which were selected to develop the fracability index are introduced in this section.

AHP-EM fracability index

In order to estimate the fracability index based on the four parameters presented in the previous section, proper weight functions should be assigned to each parameter. Here, we propose the weighting base on analytic hierarchy process-entropy method (AHP-EM). The fracability index can be formulated as:FI=i=1nSiWi(i=1,2,,n)where Si is the dimensionless value of each parameter and Wi is the weight factor corresponding to each parameter.

To calculate the FI, there are four steps to be taken:

Physico-mechanical properties

The hydrate saturation in Alaska permafrost is relatively high, with an average of more than 50% and a maximum of 75%. The layer with saturation greater than 40% is more than 10-m thick and mainly composed of sandstone and siltstone (Dai et al., 2011). The basic Physico-Mechanical properties of Alaska permafrost are listed in Table 6.

Lab experiments

In order to evaluate the feasibility of hydraulic fracturing in Alaska permafrost, ten hydrate-bearing sediments samples with the size of 10 cm × 10 cm × 10 cm

Conclusions

  • (1)

    The feasibility of hydraulic fracturing in hydrate-bearing sediment is mainly affected by its physico-mechanical properties. Brittleness is the primary factor affecting the fracability of hydrate-bearing sediments with weight reaching 0.48, followed by mineral composition (weight 0.3), hydrate saturation (weight 0.15), and then stress anisotropy (weight 0.07) in the descending order. The Large brittleness index, high mineral composition index, large hydrate saturation and large stress

CRediT authorship contribution statement

Xiaoqiang Liu: Writing - original draft, Validation, Formal analysis. Weidong Zhang: Funding acquisition, Resources. Zhanqing Qu: Methodology, Conceptualization. Tiankui Guo: Funding acquisition. Ying Sun: Software. Minou Rabiei: Writing - review & editing. Qinya Cao: Visualization.

Declaration of competing interest

The authors declared that they have no conflicts of interest to this work.

Acknowledgments

The authors would like to acknowledge the financial support of the National Natural Science Foundation of China (Grant No. 51874338 and No. 51374229), and express their gratitude to project ZD2019-184-002 supported by Major Scientific and Technological Project of CNPC, and Shandong Natural Science Foundation (Project No. ZR2019MEE101).

References (40)

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