Flue gas injection into gas hydrate reservoirs for methane recovery and carbon dioxide sequestration

Methane hydrate exists in huge amounts in certain locations, in sea sediments and the geological structures below them, at low temperature and high pressure. Production methods are in development to produce the methane to a floating platform. There it can be reformed to produce hydrogen and carbon dioxide, in an endothermic process. Some of the methane can be burned to provide heat energy to develop all needed power on the platform and to support the reforming process. After separation, the hydrogen is the valuable and transportable product. All carbon dioxide produced on the platform can be separated from other gases and then sequestered in the sea as carbon dioxide hydrate. In this way, hydrogen is made available without the release of carbon dioxide to the atmosphere, and the hydrogen could be an enabling step toward a world hydrogen economy.

Kinetic mechanisms of methane hydrate replacement and carbon dioxide hydrate reorganization

Experimental Study on a Novel Way of Methane Hydrates Recovery: Combining CO2 Replacement and Depressurization

Molecular scale modeling approach to evaluate stability and dissociation of methane and carbon dioxide hydrates

Hydrate that is exposed to fluid phases which are undersaturated with respect to equilibrium with the hydrate will dissociate due to gradients in chemical potential. Kinetic rates of methane hydrate dissociation towards pure water and seawater is important relative to hydrate reservoirs that are partly exposed towards the ocean floor. Corresponding results for carbon dioxide hydrate is important relative to hydrate sealing effects related to storage of carbon dioxide in cold aquifers. In this work we apply a phase field theory to the prediction of carbon dioxide hydrate and methane hydrate dissociation towards pure water at various conditions, some of which are inside and some which are outside the stability regions of the hydrates with respect to temperature and pressure. As expected from the differences in water solubility the methane hydrate dissolves significantly slower towards pure water than carbon dioxide hydrate.

Molecular dynamics study on growth of carbon dioxide and methane hydrate from a seed crystal

Gas hydrates, which contain the largest amount of methane on our planet, are a promising source of natural gas after the depletion of traditional gas fields, the reserves of which are estimated to last about 50 years. Therefore, it is necessary to study the methods for extracting gas from gas hydrates in order to select the best of them and make reasoned technological and engineering decisions in the future. One of these methods is the replacement of methane in its hydrate with carbon dioxide. This work studies the construction of a mathematical model to observe this method. The following process is considered in this article: on one side of a porous reservoir, initially saturated with methane and its hydrate, carbon dioxide is injected; on the opposite side of this reservoir, methane and/or carbon dioxide are extracted. In this case, both the decomposition of methane hydrate and the formation of carbon dioxide hydrate can occur. This problem is stated in a one-dimensional linear formulation for the case of negative temperatures and gaseous carbon dioxide, which means that methane, carbon dioxide, ice, methane, and carbon dioxide hydrates may be present in the reservoir. A mathematical model is built based on the following: the laws of conservation of masses of methane, carbon dioxide, and ice; Darcy’s law for the gas phase motion; equation of state of real gas; energy equation taking into account thermal conductivity, convection, adiabatic cooling, the Joule — Thomson effect, and the release or absorption of latent heat of hydrate formation. The modelling assumes that phase transitions occur in an equilibrium mode and that methane can be completely replaced by carbon dioxide. The results of numerical experiments are presented.

The geological Storage of CO2 together with the recovery of methane gas from methane hydrate reservoirs in permafrost and sub-marine areas is promised a strategy towards overcoming climate change and energy supply. The major challenge in carbon capture and storage (CCS) is the difficulty in removing and capturing CO2 from other components of air mainly nitrogen, covering the main cost in CCS. In this study, a novel economical technique, without CO2 capture process, based on direct injection of flue gas from coal-fired power plants (14 mol% CO2, and 86 mol% N2) into gas hydrate reservoirs was investigated at bulk conditions. Experiments were conducted at different typical hydrate reservoir temperatures (278.2 K, and 283.2 K) and different ratio of flue gas to initiated methane hydrate. The efficiency of both CO2 storage and methane recovery were investigated by measuring the gas composition change during step-wise depressurization of system using gas chromatography. Methane recovery was induced by flue gas injection, shifting the methane hydrate phase boundary due to driving force of changed Vapour phase composition. In addition, injected CO2 was sequestrated as different types of hydrate. Finally, it’s concluded that CO2 storage efficiency is dependent on thermodynamic condition of the experiment.

Different gas hydrate types, such as methane hydrate and carbon dioxide hydrate, exhibit distinct geomechanical responses and hydrate morphologies in gas-hydrate-bearing sediments (GHBSs). However, most constitutive models for GHBSs focus on methane-hydrate-bearing sediments (MHBSs), while largely overlooking carbon-dioxide-hydrate-bearing sediments (CHBSs). This paper proposes a modified Mohr–Coulomb (M-C) model for GHBSs that incorporates the geomechanical effects of both MHBSs and CHBSs. The model integrates diverse hydrate morphologies—cementing, load-bearing, and pore-filling—into hydrate saturation and incorporates an effective confining pressure. Its validity was demonstrated through simulations of reported triaxial compression tests for both MHBSs and CHBSs. Moreover, a variance-based sensitivity analysis using Sobol’s method evaluated the effects of hydrate-related soil properties on the geomechanical behavior of GHBSs. The results indicate that the shear modulus influences the yield axial strain of the CHBSs and could be up to 1.15 times more than that of the MHBSs. Similarly, the bulk modulus showed an approximate 5% increase in its impact on the yield volumetric strain of the CHBSs compared with the MHBSs. These findings provide a unified framework for modeling GHBSs and have implications for CO2-injection-induced methane production from deep sediments, advancing the understanding and simulation of GHBS geomechanical behavior.

Nowadays, methane hydrates are viewed as a potential energy source but their exploitation is challenging for many technical and environmental reasons. The thermodynamic conditions that govern the formation, stability, and dissociation of gas hydrates, mostly methane and carbon dioxide hydrates, their structure, mechanical, thermal, and flow properties are addressed in a fluid-saturated porous media context and brought in a computational format. Standard and prospective production methods are reviewed. Gas hydrates are solid crystalline compounds, looking like ice, formed by natural gas components, e.g. methane, ethane, hydrogen sulfide, carbon dioxide, which occupy lattice positions in the water structure. The gas is not chemically bound to water. Hydrates contribute to a large part to the mechanical properties of the hydrate-bearing sediments. Therefore, their dissociation by depressurization, thermal or chemical methods, leaves a weakened mechanical resistance that may trigger underwater slope slides over large areas. Attempts to replace methane by carbon dioxide briefly reviewed, a process that at once would enhance methane production, maintain the mechanical properties of the hydrates, and sequestrate a greenhouse gas.

The injection of flue gas is a promising cost-effective process for improving recovery from light oil reservoirs. The flue gas could be obtained directly from power plants or other surface sources. It could also be indirectly generated in situ from the spontaneous ignition of oil when air is injected into a high temperature, high pressure (light oil) reservoir. When operating at high pressures commonly found in deep light oil reservoirs, the flue gas may become miscible with the oil, thereby displacing it more efficiently. The efficiency of oil recovery during flue gas injection in light oil reservoirs was studied by flue gas displacements of light oil in a 2.44-m long Berea sandstone core at pressures up to 41.58 MPa and temperature of 116 °C in the laboratory. The laboratory results were history-matched using a compositional simulator. This study attempts to understand and explain the success achieved in field high pressure air injection projects in light oil reservoirs. The high oil recovery obtained from this study suggests that flue gas injection is a promising process for enhanced oil recovery from light oil reservoirs. The results show that the level of oil recovery was accompanied by the level of approach to miscibility between the flue gas and the oil. Both were found to increase with an increase in reservoir pressure, as well as an increase in the carbon dioxide content of the flue gas. When injected from a surface source, the sequestration of the carbon dioxide component of the flue gas (a greenhouse gas) makes the flue gas injection process an environmentally- friendly process. Introduction The solvent extraction and/or miscible-type processes are among the dominant enhanced oil recovery (EOR) methods in Canada(1). These processes include the injection of nitrogen, flue gas, carbon dioxide, hydrocarbon-miscible methods, and solvent extraction of mined, oil-bearing ores(2). They have the potential to add 300 to 400 million cubic metres (~50%) to Canada's remaining recoverable oil reserves(3) and multiples of this to the world's recoverable reserves. Other than compressed air, nitrogen and flue gas are the cheapest gases available(4). The potential for cost-effective oil recovery by flue gas injection from currently producing light oil reservoirs as well as depleted and mature waterflooded reservoirs is most important, especially for reservoirs with little or no water production and those with low porosity and low permeability(5–8) where water injection is not feasible. In recent studies carried out by the authors in a slim-tube apparatus(9–11), flue gas has been found to displace oil by mass transfer of intermediate components of the oil into the injected flue gas, and subsequent condensation of the higher molecular weight intermediates back into the liquid phase from the enriched gas phase through a multi-contact combined vapourizing-condensing gas drive mechanism(12). Although the flue gas may never displace the light oil in a truly miscible fashion because of this mechanism, the oil recovery in such a process is significant enough to make it cost-effective(10).

Hydrate phase transition kinetics from Phase Field Theory with implicit hydrodynamics and heat transport

The role of phase saturation in depressurization and CO2 storage in natural gas hydrate reservoirs: Insights from a pilot-scale study

Injection of flue gas or CO2-N2 mixtures into gas hydrate reservoirs has been considered as a promising option for geological storage of CO2. However, the thermodynamic process in which the CO2 present in flue gas or a CO2-N2 mixture is captured as hydrate has not been well understood. In this work, a series of experiments were conducted to investigate the dependence of CO2 capture efficiency on reservoir conditions. The CO2 capture efficiency was investigated at different injection pressures from 2.6 to 23.8 MPa and hydrate reservoir temperatures from 273.2 to 283.2 K in the presence of two different saturations of methane hydrate. The results showed that more than 60% of the CO2 in the flue gas was captured and stored as CO2 hydrate or CO2-mixed hydrates, while methane-rich gas was produced. The efficiency of CO2 capture depends on the reservoir conditions including temperature, pressure, and hydrate saturation. For a certain reservoir temperature, there is an optimum reservoir pressure at which the maximum amount of CO2 can be captured from the injected flue gas or CO2-N2 mixtures. This finding suggests that it is essential to control the injection pressure to enhance CO2 capture efficiency by flue gas or CO2-N2 mixtures injection.

To determine whether ultrasonic wave velocities are affected by the occurrence and amount of methane hydrate in the pore spaces of sediments, we measured ultrasonic velocities in artificial methane hydrate-bearing sandy sediments during the formation and dissociation processes of methane hydrate. An artificial core specimen was made based on the properties of a natural core recovered from a site in the Nankai Trough near Japan. A core holder was used that permitted the independent application of both confining and pore pressures to the artificial core using a rubber sleeve and two syringe pumps. Piezoelectric ceramic sensors were positioned at both end faces of the core and used to oscillate and detect the compressional and shear ultrasonic waves. The formation of methane hydrate, by pressurizing water in the pore spaces of the core sample using methane gas, was associated with an increase in both wave velocities. The increase in ultrasonic velocities was particularly marked at saturations of methane hydrate in the pore spaces above 30% and the maximum velocity of the compressional wave exceeded 3,000 m/s. While ultrasonic wave velocities decreased with the dissociation of methane hydrate due to depressurization or heating, they exhibit hysteresis during formation and dissociation. These findings indicate that the velocities depend on the occurrence of methane hydrate in pore spaces as well as the concentration. Introduction Methane hydrate has considerable potential for use as a new energy resource. Marine methane hydrate occurs in a variety forms several hundred meters below the sea floor. The form considered to be the most well suited to exploitation is that contained within the pore spaces of sandy sediments, as it has relatively larger gas permeability compared to other forms. Since shallow sandy sediments are not usually consolidated, the methane hydrate within pores acts to increase the mechanical strength of the sediments which, consequently, affects production methods. It is thought that methods employing ultrasonic wave velocities are effective for studying the occurrence of interstitial methane hydrate in sandy sediments, and also for undertaking resource assessments of methane hydrate. To determine whether ultrasonic wave velocities are affected by both the occurrence and the amount of interstitial methane hydrate, we measured ultrasonic wave velocities in artificial methane hydrate-bearing sandy sediments during the formation and dissociation of methane hydrate. A resonant column method was developed to study the seismic velocities of methane gas hydrate-bearing sand1,2. Velocities of compressional and shear waves, as well as the dynamic modulus were investigated at methane hydrate saturations below 35%; saturation is defined as the volume ratio of methane hydrate to pore space. Although measurements were performed under dry conditions, the properties under water-saturated conditions were theoretically calculated. The compressional and shear wave velocities increased to 2500 m/s and 1500 m/s at methane hydrate saturation of 35%, respectively. In the present study, ultrasonic wave velocities were measured under water-saturated conditions at methane hydrate saturations of less than 75%. The velocities were also measured at the dissociation of methane hydrate due to depressurization and heating.