Mapping Gas Hydrate Dynamics in Porous Media : Experimental Studies of Gas Hydrates as a Source of CH4 and Sink for CO2

Abstract

The world needs more energy and the energy has to be more sustainable with respect to carbon dioxide (CO2) emissions. This is the backdrop for studying the diverse applications of gas hydrates in nature. The ice-like substance is found worldwide as inclusions in the pore space of subsurface sediments and may affect the global energy supply and climate profoundly: 1) The large amounts of hydrate-bound natural gas, predominantly methane gas (CH4), could provide the world with energy for decades. Global consumption of natural gas is expected to increase with 45% by 2030 (IEA, 2018b). Countries like Japan, China, India and South Korea are seeking to increase their energy security by developing natural gas production from subsurface accumulations of gas hydrates. 2) The natural affinity for CO2 to form gas hydrates in the shallow subsurface could increase the storage capacity and security of carbon sequestration. Carbon capture and storage (CCS) is the removal of CO2 from the atmosphere (or before it reaches the atmosphere) and subsequent long-term storage of the CO2 in the subsurface. The projections of the IPCC that seeks to limit global warming to 1.5°C above the pre-industrial level rely on the use of CO2 removal from the atmosphere on the order of 100 – 1000 gigatonnes of CO2 (GtCO2) during this century (IPCC, 2018). The formation of CO2 hydrates could provide a self-sealing mechanism during CO2 storage in saline aquifers which would decrease the risk of CO2 leakage considerably. In both cases, fundamental knowledge about gas hydrates in porous media is needed. The scientific work presented in this thesis contributes to the understanding of CH4 and CO2 hydrates in sediments with special emphasis on phase transitions and fluid flow in hydrate-saturated porous rock. Coupling the fluid flow with gas hydrate saturation and growth pattern is important to control the production rate of CH4 gas from CH4 gas hydrates and to model the sealing capacity of CO2 gas hydrates. The rate and distribution of fluid flow during gas hydrate phase transitions in sediments were studied using a multiscale approach. Permeability measurements and quantitative mapping of water saturation were conducted on cylindrical Bentheim sandstone core plugs by high-precision pressure-volume-temperature (PVT) recordings and magnetic resonance imaging (MRI). Pore-scale mapping of gas hydrate phase transitions was facilitated by etched silicon micromodels with pore networks replicating the geometry of real sandstone rock. The qualitative observations of phase transitions at pore-scale helped explain the flow rates measured at core-scale. This thesis consists of seven scientific papers presenting a detailed description of gas hydrates effect on fluid flow in porous media. The first step in every gas hydrate experiment is to establish gas hydrates in the pore space and this was particularly investigated in paper 1. The effect of heterogeneous water distribution on CH4 hydrate growth was resolved in Bentheim sandstone core plugs by MRI. The growth of CH4 hydrate was more profound in regions of the core plug saturated with high water content and the final CH4 hydrate distribution mirrored the initial water distribution. The same growth pattern of CH4 hydrate was observed in the micromodel in paper 2 and further developed into a conceptual growth model based on the initial pore-scale fluid distribution: A) A porous hydrate with encapsulated CH4 gas surrounded by a shell of CH4 hydrate formed in regions with high CH4 gas saturation. B) A solid nonporous hydrate with no CH4 gas formed in regions with low CH4 gas saturation. The final hydrate morphology was mainly governed by local availability of water and mass transfer of water/CH4 across the hydrate layer at the gas-water interface. In paper 3, the controlling mechanisms on the rate of CH4 gas recovery from CH4 hydrates were investigated via constant pressure dissociation in Bentheim sandstone core plugs. The maximum rate of CH4 gas recovery was governed by the CH4 hydrate saturation and the rate was highest in the CH4 hydrate saturation interval of 0.30 – 0.50 (frac.). The CH4 gas recovery was slower at higher CH4 hydrate saturation because of ineffective pressure transmission through the pore network and low relative permeability of the liberated CH4 gas. The relative permeability to CH4 (or CO2) in gas hydrate-filled sandstone rock was measured in paper 4. The addition of solid hydrates in the pore space reduced the effective permeability to both CH4 and CO2 at constant CH4 (or CO2) saturation. The fitting exponent, n, in the modified Brooks-Corey curve increased during hydrate growth for both CH4 and CO2. The exponent increased from 2.7 to 3.6 when CH4 hydrates formed in the pores and from 4.0 to 5.8 when CO2 hydrates formed. The effective permeability to CH4 (or CO2) was more sensitive to inclusion of hydrates in the pores at low CH4 (or CO2) saturations, most likely because the limited CH4 (or CO2) phase was more prone to become disconnected and capillary immobilized. The ability of CO2 hydrates to immobilize CO2 in water-saturated rock was explored in paper 5-7. The nature of CO2 hydrate sealing during CO2 injection was revealed at both micro- and core-scale in paper 5. Liquid CO2 was completely immobilized by surrounding CO2 hydrates that initially had formed at the CO2-water interface and then later crystallized the water phase into nonporous CO2 hydrates. The long-term sealing capability of the formed CO2 hydrates was tested for different rock core samples in paper 6-7. In quartz-dominated rock core plugs, the CO2 hydrate plug formed faster in tight rocks with low absolute permeability. Narrow pore throats in tight rocks were more easily obstructed by thin hydrate films that formed early in the nucleation process. The CO2 hydrate formed later in an Edwards limestone core plug (Kabs = 80 mD) than in a Bentheim sandstone core plug (Kabs = 1500 mD) despite having a lower absolute permeability. The leakage rate of CO2 through the CO2 hydrate plug was higher in the limestone core plug compared to the sandstone core plug. The CO2 hydrate self-sealing was therefore slower and less robust in carbonate rock compared to quartz-dominated rock.