Nariman Mahabadi

The water retention curve and relative permeability for gas production from hydrate‐bearing sediments: pore‐network model simulation

The water retention curve and relative permeability are critical to predict gas and water production from hydrate-bearing sediments. However, values for key parameters that characterize gas and water flows during hydrate dissociation have not been identified due to experimental challenges. This study utilizes the combined techniques of micro-focus X-ray computed tomography (CT) and pore-network model simulation to identify proper values for those key parameters, such as gas entry pressure, residual water saturation, and curve fitting values. Hydrates with various saturation and morphology are realized in the pore-network that was extracted from micron-resolution CT images of sediments recovered from the hydrate deposit at the Mallik site, and then the processes of gas invasion, hydrate dissociation, gas expansion, and gas and water permeability are simulated. Results show that greater hydrate saturation in sediments lead to higher gas entry pressure, higher residual water saturation, and steeper water retention curve. An increase in hydrate saturation decreases gas permeability but has marginal effects on water permeability in sediments with uniformly distributed hydrate. Hydrate morphology has more significant impacts than hydrate saturation on relative permeability. Sediments with heterogeneously distributed hydrate tend to result in lower residual water saturation and higher gas and water permeability. In this sense, the Brooks-Corey model that uses two fitting parameters individually for gas and water permeability properly capture the effect of hydrate saturation and morphology on gas and water flows in hydrate-bearing sediments.

Relative water and gas permeability for gas production from hydrate‐bearing sediments

Relative water and gas permeability equations are important for estimating gas and water production from hydrate-bearing sediments. However, experimental or numerical study to determine fitting parameters of those equations is not available in the literature. In this study, a pore-network model is developed to simulate gas expansion and calculate relative water and gas permeability. Based on the simulation results, fitting parameters for modified Stone equation are suggested for a distributed hydrate system where initial hydrate saturations range from Sh = 0.1 to 0.6. The suggested fitting parameter for relative water permeability is nw ≈ 2.4 regardless of initial hydrate saturation while the suggested fitting parameter for relative gas permeability is increased from ng = 1.8 for Sh = 0.1 to ng = 3.5 for Sh = 0.6. Results are relevant to other systems that experience gas exsolution such as pockmark formation due to sea level change, CO2 gas formation during geological CO2 sequestration, and gas bubble accumulation near the downstream of dams.

The effect of hydrate saturation on water retention curves in hydrate‐bearing sediments

The experimental measurement of water retention curve in hydrate-bearing sediments is critically important to understand the behavior of hydrate dissociation and gas production. In this study, tetrahydrofuran (THF) is selected as hydrate former. The pore habit of THF hydrates is investigated by visual observation in a transparent micromodel. It is confirmed that THF hydrates are not wetting phase on the quartz surface of the micromodel and occupy either an entire pore or part of pore space resulting in change in pore size distribution. And the measurement of water retention curves in THF hydrate-bearing sediments with hydrate saturation ranging from Sh = 0 to Sh = 0.7 is conducted for excess water condition. The experimental results show that the gas entry pressure and the capillary pressure increase with increasing hydrate saturation. Based on the experimental results, fitting parameters for van Genuchten equation are suggested for different hydrate saturation conditions.

Effect of capillary and viscous force on CO2 saturation and invasion pattern in the microfluidic chip

Carbon dioxide sequestration into geological formations has been identified as an alternative to mitigate the global climate change. The CO2 invasion pattern is dependent on various factors such as fluid viscosity, interfacial tension, injection rate, and the characteristics of porous media. Among these variables, we provide a systematic experimental study on the influence of the injection rate and the phase of CO2 invading into a brine-saturated microfluidic chip in order to quantitatively assess the displacement ratio. Interfacial tension and contact angle are accurately measured under the temperature and pressure conditions relevant to in situ conditions. The injection rate varies 3 orders of magnitude for gaseous, liquid, supercritical CO2, and CO2-water foam invasion. The capillary number and the viscosity ratio are calculated for each experimental condition, and the displacement ratio (CO2 saturation) is obtained after CO2 invasion. The results show that the saturation of injected CO2 is controlled by manipulating the injection rate and the phase of invading fluid, which can be used to optimize the in situ storage capacity. Especially, the CO2-water foam displaces almost all brine out of the microfluidic chip, but the increase in CO2 saturation is 23% ~ 53% compared to pure gaseous CO2 injection due to the water initially mixed in the CO2-water foam. The potential advantages of using CO2-water foam in the geological CO2 sequestration were also discussed.

The impact of fluid flow on force chains in granular media

Fluid flow through granular media is an important process found in nature and various engineering applications. The effect of fluid flow on the evolution of force chains in the granular media is explored using the photoelasticity theory. A transparent cell is designed to contain several photoelastic disks of different sizes and to allow fluid flow through the particle packing. Water is injected into the cell while the particle packing is under confining stress. Several images are taken for the conditions of different confining stresses and fluid injection rates. An algorithm of an image processing technique is developed to detect the orientation and magnitude of contact forces. The results show that forces in parallel and transverse to the flow direction increase with increasing water velocity, while parallel force shows a higher increasing rate.

Gas Bubble Migration and Trapping in Porous Media: Pore‐Scale Simulation

This work was supported by the research fund of Hanyang University (HY-201700000002411). The data presented in this study are available at http://jwjang1977.wixsite.com/mysite/data.

Water Permeability Reduction in THF Hydrate-Bearing Sediments

Water permeability in hydrate-bearing sediments is a key parameter in gas production affecting the effective depressurization boundary from a wellbore and contributing heat transport associated with fluid flow. The experimental measurement of water permeability in the presence of hydrates is associated with many difficulties such as dynamic hydrate dissolution and formation during fluid flow and long induction time. In this study, we formed tetrahydrofuran (THF) hydrates in a core-scale chamber to explore water permeability as a function of hydrates. Wave velocities during the permeability measurement were also measured. The results show that water permeability decreases as hydrate saturation increases. Shear and compression wave velocities increase with increasing hydrate saturation, but the velocity decreases a little during the repetitive permeability measurement at a given hydrate saturation.

Gas Bubble Nucleation and Migration in Soils—Pore-Network Model Simulation

Sediment can be de-saturated by introducing gas bubbles, which is found in various applications such as methane gas generation in landfill, microbial-induced gas bubble formation, air sparing method for soil remediation, heavy oil depressurization for carbon recovery, and gas production from hydrate bearing sediment. The gas introduction method (e.g., nucleation and injection) and migration and trapping of gas bubbles affect the hydraulic conductivity, residual gas saturation, and the stability of these gassy sediments. In this study, the pore-network model is used to investigate gas bubble migration in porous media. Gas bubbles are introduced by mimicking either nucleation or injection. Based on the known gas bubble behavior available in the literature, numerical algorithms are developed to simulate the migration and trapping of gas bubbles in pore-network model. The effect of gas bubble size distribution and pore size distribution on residual saturation is investigated. The results show that gas bubble size distribution becomes wider as gas bubbles coalesce to each other during migration. And the residual gas saturation increase with increasing bubble size and permeability reduction becomes apparent as the gas bubble size and the number of generated gas bubble increase.