Quantification of CH4 Hydrate Film Growth Rates in Micromodel Pores

In this paper, we report the growth pattern and the rate of CH4 hydrate in sandstone pores. A high-pressure, water-wet, transparent micromodel with pores resembling a sandstone rock was used to visualize CH4 hydrate formation at reservoir conditions (P = 35–115 bar and T = 0.1–4.9 °C). The CH4 hydrate preferably formed and grew along the gas–water interface until the gas phase was completely encapsulated by a hydrate film. Two different growth rates were identified on the gas–water interface: CH4 hydrate film growth along the vertical pore walls (∼1200 μm/s) was more than 100 times faster than the film growth toward the pore center (∼8 μm/s). CH4 hydrate crystal growth directly in the water phase was slow and the rate was less than 0.5 μm/s. The film growth rate along the gas–water interface was independent of the pore size, gas saturation, and gas distribution, but the pore wall growth rate displayed a power law dependency on the applied subcooling temperature, ΔT, with a power law exponent equal to 2. The results of this study can be used as input to numerical models aiming to simulate pore-scale CH4 hydrate growth behavior.publishedVersio

Pore-scale dynamics for underground porous media hydrogen storage

Underground hydrogen storage (UHS) has been launched as a catalyst to the low-carbon energy transitions. The limited understanding of the subsurface processes is a major obstacle for rapid and widespread UHS implementation. We use microfluidics to experimentally describe pore-scale multiphase hydrogen flow in an aquifer storage scenario. In a series of drainage-imbibition experiments we report the effect of capillary number on hydrogen saturations, displacement/trapping mechanisms, dissolution kinetics and contact angle hysteresis. We find that the hydrogen saturation after injection (drainage) increases with increasing capillary number. During hydrogen withdrawal (imbibition) two distinct mechanisms control the displacement and residual trapping – I1 and I2 imbibition mechanisms, respectively. Local hydrogen dissolution kinetics show dependency on injection rate and hydrogen cluster size. Dissolved global hydrogen concentration corresponds up to 28% of reported hydrogen solubility, indicating pore-scale non-equilibrium dissolution. Contact angles show hysteresis and vary between 17 and 56° Our results provide key UHS experimental data to improve understanding of hydrogen multiphase flow behaviour.publishedVersio

Hydrogen Relative Permeability Hysteresis in Underground Storage

Implementation of the hydrogen economy for emission reduction will require storage facilities, and underground hydrogen storage (UHS) in porous media offers a readily available large-scale option. Lack of studies on multiphase hydrogen flow in porous media is one of the several barriers for accurate predictions of UHS. This paper reports, for the first time, measurements of hysteresis in hydrogen-water relative permeability in a sandstone core under shallow storage conditions. We use the steady state technique to measure primary drainage, imbibition and secondary drainage relative permeabilities, and extend laboratory measurements with numerical history matching and capillary pressure measurements to cover the whole mobile saturation range. We observe that gas and water relative permeabilities show strong hysteresis, and nitrogen as substitute for hydrogen in laboratory assessments should be used with care. Our results serve as calibrated input to field scale numerical modeling of hydrogen injection and withdrawal processes during porous media UHS.publishedVersio

Experimental Investigation of Critical Parameters Controlling CH4− CO2 Exchange in Sedimentary CH4 Hydrates

Sequestration of CO2 in natural gas hydrate reservoirs may offer stable long-term deposition of a greenhouse gas while benefiting from CH4 gas production. In this paper, we review old and present new experimental studies of CH4–CO2 exchange in CH4 hydrate-bearing sandstone core plugs. CH4 hydrate was formed in Bentheim sandstone core plugs to prepare for subsequent lab-scale CH4 gas production by CO2 replacement. The effect of temperature, diffusion length, salinity, water saturation, CH4 hydrate saturation, and co-injection of chemicals (N2 and monoethanolamine) with the injected CO2 were measured. The measurements prove the critical role of water saturation in these processes: formation of CO2 hydrate severely reduced the injectivity for water saturations above 0.1 fractions. The results presented in this paper are important when assessing natural gas hydrate reservoirs as candidates for CO2 injection with concurrent CH4 gas production.publishedVersio

Transport and storage of CO2 in natural gas hydrate reservoirs

Storage of CO2 in natural gas hydrate reservoirs may offer stable long term deposition of a greenhouse gas while benefiting from methane production, without requiring heat. By exposing hydrate to a thermodynamically preferred hydrate former, CO2, the hydrate may be maintained macroscopically in the solid state and retain the stability of the formation. One of the concerns, however, is the flow capacity in such reservoirs. This in turn depends on three factors; 1) thermodynamic destabilization of hydrate in small pores due to capillary effects, 2) the presence of liquid channels separating the hydrate from the mineral surfaces and 3) the connectivity of gas- or liquid filled pores and channels. This paper reports experimental results of CH4- CO2 exchange within sandstone pores and measurements of gas permeability during stages of hydrate growth in sandstone core plugs. Interactions between minerals and surrounding molecules are also discussed. The formation of methane hydrate in porous media was monitored and quantified with magnetic resonance imaging techniques (MRI). Hydrate growth pattern within the porous rock is discussed along with measurements of gas permeability at various hydrate saturations. Gas permeability was measured at steady state flow of methane through the hydrate-bearing core sample. Experiments on CO2 injection in hydrate-bearing sediments was conducted in a similar fashion. By use of MRI and an experimental system designed for precise and stabile pressure and temperature controls flow of methane and CO2 through the sandstone core proved to be possible for hydrate saturations exceeding 60%.publishedVersio

Effects of salinity on hydrate stability and implications for storage of CO2 in natural gas hydrate reservoirs

The win-win situation of CO2 storage in natural gas hydrate reservoirs is attractive for several reasons in addition to the associated natural gas production. Since both pure CO2 and pure methane form structure I hydrate there is no expected volume change by replacing the in situ methane with CO2, and there is not net production of associated water which requires extra handling. The geo-mechanical implication of the first of these may be a very important issue since hydrates in unconsolidated sediments are the most promising targets for exploitation of natural gas. The stability of CO2 stored in the form of hydrate is probably one of the safest options today, even though also this option relates to safety of sealing cap-rock or clay layer. The stability of hydrates in a reservoir depends on many factors, including the interactions between minerals, surrounding fluids and hydrate. The natural level of salinity increases with depth in a reservoir. In addition formation of hydrate will lead to increased salinity of the fluids surrounding the formed hydrate. This may lead to liquid pockets of residual aqueous solution with increased salinity as well as very non-uniform hydrate. The latter due to the fact that hydrate composition and stability relates to properties of surrounding fluids. In the work presented here methane hydrates were formed in several sandstone cores. The cores were all partially saturated with brine of different salinities in order to identify the effect salinity has on the fill fraction, the amount of methane per available structural site in hydrates. The results indicate that salinities lower than regular sea water composition has no significant impact on the fill fraction of methane hydrate in porous media. When the salinity surpasses regular sea water composition there is a significant drop in fill fraction. The methane hydrate fill fraction is dominated by total brine salinity rather than brine distribution in the core.publishedVersio