Jinhai Yang

SUBSURFACE CARBON DIOXIDE STORAGE THROUGH CLATHRATE HYDRATE FORMATION

Rising atmospheric emissions as a result of fossil fuel consumption is a major concern for the developed and developing countries, considering the role it plays in the greenhouse effect and hence global climate change. Various schemes for underground CO2 storage (viz. geologic disposal into coal seams, depleted oil/gas reservoirs, salt caverns, and deep oceans) have already been reported in the literature. Subsurface CO2 storage through clathrate hydrate formation is a novel option for the reduction of atmospheric carbon content and permanent underground CO2 disposal over geological periods. Depths of CO2 injection, respective pressure-temperature conditions, water salinity etc. are all important factors for successful CO2 sequestration. Furthermore if CO2 is injected/stored in methane hydrate reservoirs it could be possible to produce low-carbon methane energy, thereby offsetting the cost of CO2 transportation and disposal. In this communication, we present the results of experiments carried out to understand the mechanisms of CH4 displacement in hydrate structure by injected CO2 and the formation of simple CO2 or mixed CH4-CO2 hydrates, thereby simulating the conditions of CO2 injection into CH4 hydrate reservoirs. We used two sets of experimental rigs specifically designed for studying gas hydrates in porous media. They are the Medium Pressure Glass Micromodel (80 bar) for visual observation of gas hydrate formation / dissociation and distribution in porous media, and the Ultrasonic Rig (400 bar) for studying CO2 sequestration in CH4 hydrates in synthetic porous media.

Seismic time-lapse monitoring of potential gas hydrate dissociation around boreholes - could it be feasible? A conceptual 2D study linking geomechanical and seismic FD models

Monitoring of the seafloor for gas hydrate dissociation around boreholes during hydrocarbon production is likely to involve seismic methods because of the strong sensitivity of P-wave velocity to gas in sediment pores. Here, based on geomechanical models, we apply commonly used rock physics modeling to predict the seismic response to gas hydrate dissociation with a focus on P-impedance and performed sensitivity tests. For a given initial gas hydrate saturation, the mode of gas hydrate distribution (cementation, frame-bearing, or pore-filling) has the strongest effect on P-impedance, followed by the mesoscopic distribution of gas bubbles (evenly distributed in pores or “patchy”), gas saturation, and pore pressure. Of these, the distribution of gas is likely to be most challenging to predict. Conceptual 2-D FD wave-propagation modeling shows that it could be possible to detect gas hydrate dissociation after a few days.

CO2 Capture by Injection of Flue Gas or CO2–N2 Mixtures into Hydrate Reservoirs: Dependence of CO2 Capture Efficiency on Gas Hydrate Reservoir Conditions

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.

Thermodynamic conditions and kinetics of integrated methane recovery and carbon dioxide sequestration

Jinhai Yang, Antonin Chapoy, Bahman Tohidi, Prashant Sopanrao Jadhawar, JaeHyoung Lee, Dae Gee Huh

A novel method for CO2 storage and methane recovery in gas hydrate reservoirs through injection of flue gas from coal-fired power plants

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.

A Novel Technique for Monitoring Hydrate Safety Margin

Great concerns with flow assurance issues have been raised by the oil and gas industry, while the industry is increasingly moving to deepwater reservoirs. Gas hydrate blockages are one of the most common risks for the long distance offshore gas and oil production transport pipelines. Various types of hydrate inhibitors are usually deployed to ensure unimpeded flow of hydrocarbons. At present hydrate inhibitors are injected at the upstream of the pipelines according to approximate assessment of the flowing conditions including the produced water cut and the hydrate phase boundary that is determined based on the worst temperature and pressure conditions, without any means of monitoring the actual degree of inhibition along the pipeline. A novel technique has been developed to optimize the injection of hydrate inhibitors by monitoring the actual hydrate safety margin (i.e., degree of inhibition), which makes it possible to reduce unnecessary cost and potential impact on the environment. It measures the acoustic velocity and electrical conductivity of downstream aqueous samples and then determines both the inhibitor concentration and salt concentration through a trained artificial neural network. The hydrate phase boundary, hence the hydrate safety margin, are finally determined by an integrated in-house thermodynamic model using the determined salt and inhibitor concentrations. Its performance has been intensively evaluated using synthetic samples and real produced water samples by the authors and some oil & gas and service companies. This communication reports the success in development of the hydrate inhibition monitoring system. Results of the evaluation demonstrate that the system can be used for different inhibition systems including methanol-salt systems, mono ethylene glycol- salt systems, and kinetic hydrate inhibitor-salt systems with an acceptable measurement accuracy.