Influence of gas hydrate saturation and pore habits on gas relative permeability in gas hydrate-bearing sediments: Theory, experiment and case study

Highlights

• The correlation of the Corey exponent and gas hydrate saturation was examined.

• A new gas relative permeability-based gas hydrate saturation calculation model was developed.

• Variation law of gas hydrate microscopic distribution in gas hydrate formation process was investigated.

• The effect of gas hydrate pore-habits on gas relative permeability was studied.

Abstract

Gas relative permeability characterization is of key significance to model the behavior of gas flow in gas hydrate-bearing sediments. The present study proposes a novel model to relate gas relative permeability to gas hydrate saturation based on X-ray micro-CT imaging information of xenon hydrate pore-scale distribution in sand sediments. Lattice Boltzmann method (LBM) was used to obtain permeability values of xenon hydrate-bearing sediments via micro-CT data. The results showed that gas relative permeability (K_r) versus gas hydrate saturation (S_h) data are consistent with the new model and the imitative effect is relatively better than that of the simple Corey model. Besides, we calculated gas relative permeability versus gas hydrate saturation curves for various pore habits via idealized models. Experimental measurements and simulation results showed that the grain-coating gas hydrate exhibits the highest gas relative permeability, while pore-filling gas hydrate exhibits the lowest values of gas relative permeability, and the cementing gas hydrate ranges in between. We validated the new gas relative permeability calculation model by applying it to the well logging data of gas hydrate reservoirs. Our results showed that the novel model is beneficial for permeability characterization of gas hydrate reservoirs and gas relative permeability calculations.

Introduction

Gas hydrates are considered as a clean energy resource and can effectively mitigate environmental pollution while guaranteeing energy security (Song et al., 2014; Zhao et al., 2017). Gas hydrates are mainly distributed in permafrost regions and deep-sea sediments (Koh et al., 2011; Chen et al., 2018; Dong et al., 2019). China's marine geologists extracted high-purity gas hydrate samples from the eastern waters of the Pearl River Estuary and obtained considerable control reserves through drilling. China Geological Survey began to extract natural gas from the South China Sea from May 10, 2017 to July 9, 2017. During the trial production process for 60 consecutive days, the cumulative gas production exceeded 300 × 10³ m³ and 6.47 × 10⁶ scientific experimental data sets were obtained, laying a solid foundation for further work (Cui et al., 2018). Great advances have been achieved in the fundamental characteristics, accumulation mechanisms, reservoir characterization, and production trials of natural gas hydrate (Zhang et al., 2017; Wang et al., 2018a; Li et al., 2021). For the reservoir development and exploitation perspective, gas or water relative permeability and gas production rate are key parameters as it significantly influences productivity and thus economy (Nimblett and Ruppel, 2003).

Gas and water relative permeability of gas hydrate-bearing sediments has been investigated experimentally and numerically (Konno et al., 2010; Li et al., 2013; Delli and Grozic, 2014; Jang and Santamarina, 2014; Wang et al., 2015a, 2016, 2016; Dong et al., 2018a; Mahabadi et al., 2019). For instance, Li et al. (2014) measured gas relative permeability in gas hydrate-bearing sediments via nuclear magnetic resonance (NMR) experiments, while Kneafsey et al. (2011) estimated gas and water relative permeabilities with the modified Carman-Kozeny equation using X-ray tomography experiments, and Konno et al. (2015) investigated how gas relative permeability correlated with gas hydrate saturation. By contrast, when studying the relationship between water relative permeability and gas hydrate saturation, Dai and Seol (2014) took pore habits and mesoscale heterogeneity into consideration. These data matched the simple Corey model (Corey et al., 1956); therefore, the Corey exponent was related to gas hydrate pore habits (Konno et al., 2015; Chen et al., 2018), while some K_r-S_h data suggested a pore-filling gas hydrate distribution (Kneafsey et al., 2011). Another study related upper and lower bounds of gas relative permeability to grain-coating and pore-filling gas hydrate models, respectively (Dai et al., 2012). These results were supported by pore network modeling studies (Liang et al., 2010; Dai and Seol, 2014; Wang et al., 2015b), and Li et al. (2014) studied the effect of pore-filling gas hydrate on the permeability and found that there were many factors influencing permeability.

Furthermore, gas relative permeability is determined by gas hydrate saturation, which also influences the Corey exponent (Kumar et al., 2010; Kang et al., 2016). Interestingly, grain-coating gas hydrate transforms into pore-filling distribution mode with increase of gas hydrate saturation (gas hydrate saturation in the range from 0.2 to 0.4). Nevertheless, precise characterization of gas relative permeability of gas hydrate-bearing sediments is an active area of research, and there is a gap of understanding how gas relative permeability relates to the gas hydrate saturation and pore habits (idealized as grain-coating, cementing, or pore-filling modes (Waite et al., 2009; Jiang et al., 2014; Wang et al., 2018b; Lei et al., 2019).

Thus, we investigated the correlation between gas relative permeability, gas hydrate saturation, and pore habits to better and fundamentally explain the influence of pore-scale distribution on the correlation of gas relative permeability and gas hydrate saturation.