Transport Properties of Hydrate Bearing Formations from Pore-Scale Modeling

Abstract

Gas hydrates are an attractive source of energy as natural gas can be produced from these deposits by depressurization or thermal stimulation. Empirical correlations developed in hydrology and petroleum engineering have been used for describing transport properties of sediments containing gas hydrates in hydrate simulators. The goal of this work is to estimate the transport properties of hydrate-bearing sediments from pore-scale modeling. Sediment particles have been packed using a discrete element method and pore radius distribution is calculated using Delaunay triangulation. Hydrate deposition is modeled in a single pore to develop pore-scale laws of hydrate occupancy. Pore radius distributions are recalculated after hydrate deposition. Percolation theory is used to numerically calculate effective transport properties of the medium at different saturations. Pore-scale models showed that the hydrates form at the pore walls if deposited from the flow of methane-saturated water alone. The saturation of hydrate deposited in different size pores was found to be uniform. A Gaussian distribution of particle size of the sediment results in a Rayleigh distribution of pore throat radius. As the variance of the particle size increases, so does the width of the pore size distribution. As the hydrate saturation increases, the permeability of the sediment decreases. This decrease follows Civan's correlation with a ß of 0.75. The relative permeability becomes increasingly dependent on water saturation as the hydrate saturation in the sediment increases. A new correlation for relative permeability is developed by matching the percolation theory estimates. Introduction Gas hydrates are ice-like structures of gas (e.g. methane) and water molecules (Sloan, 1998). They form at high pressure and low temperature conditions. Methane reactes with water to form hydrates according to the following equation: EQUATION where n is the hydration number. Hydrates of hydrocarbon gases occur naturally in large quatities in marine and arctic environments. Hydrate of methane gas contains 164 times the amount of methane in same volume as compared to volume of pure gas at standard conditions. This makes hydrate reservoirs a potential energy source. Hydrates can pose hazard to global climate if the naturally occurring hydrates would dissociate due to global warming. An efficient and safe method of producing natural gas from hydrate reservoirs is necessary to make the production commercial. Different methods and their combinations for the production from hydrates have been proposed: depressurization, thermal stimulation, inhibitor injection, and CO2 injection (Makogon, 1997; Ji et al., 2001; Graue et al., 2006). Laboratory experiments have been conducted to demonstrate the feasibility of these methods of hydrate dissociation. Many numerical simulation efforts at the reservoir scale have been made to estimate the production strategies of hydrate reservoirs (Moridis et. al. 2008, Phirani and Mohanty, 2009, Phirani et. al. 2009). US DOE has conduncted a code comparison study to compare several simulators of hydrates available today (Wilder et.al, 2008).

State-of-the-Art of Gas Hydrates and Relative Permeability of Hydrate Bearing Sediments

“…Interestingly, the presence of methane gas hydrates, possessing different shape and sizes (Waite et al 2009;Gabitto and Tsouris 2010), has been identified in both onshore and offshore sediments, where these stability conditions co-exist (Kvenvolden and Lorenson 2001;Kvenvolden and Rogers 2005;Tréhu et al 2006). However, any slight variation 4 (lowering pressure and/or increasing temperature) from these critical combinations would result in 'dissociation' of gas hydrates into free gas and water (Dickens et al 1994;Kvenvolden and Rogers 2005;Tréhu et al 2006;Andersen et al 2008) and hence, extraction of methane gas from these sediments could be possible just by altering their stability conditions (viz., pressure and temperature), as stated by earlier researchers (Sloan 2003;Pooladi-Darvish 2004;Moridis and Sloan 2007;Kleinberg 2009;Phirani, Pitchumani, and Mohanty 2009;Demirbas 2010;Liang et al 2010;Johnson, Patil, and Dandekar 2011).…”

“…It is observed that 1 m 3 of methane gas hydrates, with a cage occupancy of 100% methane in their crystal, on dissociation yields 172 m 3 of methane gas at 0°C and one atm. However, the cage occupancy of the methane gas hydrates from marine sediments in crystal lattice varies from 90 to 95% and this accounts for almost 164 m 3 of methane gas on hydrate dissociation (Moridis and Sloan 2007;Phirani, Pitchumani, and Mohanty 2009;Demirbas 2010;Shukla, Tyagi, and Bhowmick 2012). Interestingly, the same quantity (1 m 3 ) of gas hydrates beneath 1 km water depth, will only dissociate to 1.1 m 3 of free gas, due to extremely high pressures (10 MPa) (Anderson 2008).…”

“…This results in a multi-phase (viz., gas and liquid) fluid flow through the sediments. A few laboratory (Kumar et al 2010;Johnson, Patil, and Dandekar 2011;) and numerical studies (Phirani, Pitchumani, and Mohanty 2009;Liang et al 2010;) have been carried out for determination of permeability characteristics (viz., fluid flow characteristics) of hydrate bearing sediments and based on these studies, researchers have opined that these characteristics vary mainly depending upon the grain size, porosity (Minagawa et al 2008;Liang et al 2010), forms of the hydrates (i.e., grain coating or pore filling), their saturation (Waite et al 2009) and amount of gas evolved due to the hydrate dissociation (Liu and Flemings 2007). Further, the formation of gas hydrates reduces the available pore size and builds up capillary pressure, which in turn reduces the permeability of the gas hydrate bearing sediments .…”

“…This mechanism can be quantified by employing the term 'permeability', which governs the gas production potential from any hydrate bearing zone (Moridis and Collett 2003;Kleinberg 2009;Pohlman et al 2009). Here, it should also be considered that the absolute permeability of one fluid will be affected by the presence of other fluid(s) (Kleinberg et al 2003;Phirani, Pitchumani, and Mohanty 2009;Liang et al 2010;Johnson, Patil, and Dandekar 2011), and therefore, it is essential to determine the relative permeability of the fluids (gas and water), at different 'hydrate occupancy' or 'hydrate saturation', which is defined as percentage of pore space occupied by hydrates (Minagawa et al 2008;Kumar et al 2010;Johnson, Patil, and Dandekar 2011;Jang and Santamarina 2014).…”

“…Furthermore, determination of permeability, through conventional flow tests has been opined to be quite an intricate task that entails maintenance of constant thermodynamic conditions (Kumar et al 2010;Johnson, Patil, and Dandekar 2011;Jang and Santamarina 2014). Similarly, though some efforts have been made by the researchers (Phirani, Pitchumani, and Mohanty 2009;Liang et al 2010; to determine permeability of such sediments by resorting to numerical models, these involve over simplified assumptions such as (i) the absence of free gas and (ii) variable hydrate occupancy in the pores, which might not be resembling the real life conditions. Under these circumstances, either employing empirical correlations or application of indirect methods such as electrical impedance, which has been shown to be a very powerful tool to determine permeability of saturated and unsaturated soils by earlier researchers (Kalinski and Kelly 1994;Abu-Hassanein, Benson, and Lisa 1996;Sreedeep and Singh 2005;Rao and Singh 2012), seem to be viable options for determining the permeability of the gas hydrate bearing sediments.…”